As filed with the Securities and Exchange Commission on October 2, 2018

Registration No. 333-            

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

EnVen Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)

Delaware	1311	35-2547516
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

Three Allen Center

333 Clay Street, Suite 4200

Houston, Texas 77002

713-335-7000

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

Steven A. Weyel

Chairman and Chief Executive Officer

EnVen Energy Corporation

Three Allen Center

333 Clay Street, Suite 4200

Houston, Texas 77002

713-335-7000

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent For Service)

Copies to:

Richard D. Truesdell, Jr. Byron B. Rooney Davis Polk & Wardwell LLP 450 Lexington Avenue New York, New York 10017 (212) 450-4000 Arthur D. Robinson David W. Azarkh Simpson Thacher & Bartlett LLP 425 Lexington Avenue New York, New York 10017 (212) 455-2000

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”) check the following box.  ☐

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

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

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒  (Do not check if a smaller reporting company)	Smaller reporting company	☐
		Emerging growth company	☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☒

CALCULATION OF REGISTRATION FEE

Title Of Each Class Of Securities To Be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount Of Registration Fee
Class A Common Stock, par value $0.01 per share	$100,000,000	$12,120

(1) Includes             shares to be sold upon exercise of the underwriters’ option to purchase additional shares. See “Underwriting.”

(2) Estimated solely for the purpose of computing the amount of the registration fee pursuant to Rule 457(o) under the Securities Act.

The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and we are not soliciting offers to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED OCTOBER 2, 2018

PRELIMINARY PROSPECTUS

            Shares

EnVen Energy Corporation

Class A Common Stock

EnVen Energy Corporation is offering              shares of its Class A common stock.

This is our initial public offering and no public market exists for our Class A common stock. We anticipate that the initial public offering price will be between $        and $        per share.

We intend to apply to list our Class A common stock on The New York Stock Exchange (the “NYSE”) under the symbol “ENVN.”

We will have two classes of common stock outstanding after this offering: Class A common stock and Class B common stock. Each share of Class A common stock and Class B common stock entitles its holder to one vote on all matters presented to our stockholders generally. All of our Class B common stock will be held by EnVen Equity Holdings (as defined below). Immediately following this offering, the holders of our Class A common stock will collectively hold    % of the economic interests in us and     % of the voting power in us, and EnVen Equity Holdings, through its ownership of all of the outstanding Class B common stock, will hold the remaining     % of the voting power in us. We are a holding company and our sole material asset is the common units of EnVen GoM (as defined below), representing an    % economic interest in EnVen GoM immediately following this offering. The remaining     % economic interest in EnVen GoM is owned by EnVen Equity Holdings through its ownership of common units of EnVen GoM.

We are an “emerging growth company” as defined by the Jumpstart Our Business Startups Act of 2012 and, as such, we have elected to comply with certain reduced public company reporting requirements for this prospectus and future filings. See “Prospectus Summary—Implications of Being an Emerging Growth Company.”

Investing in our Class A common stock involves risks. See “Risk Factors” beginning on page 25.

Neither the Securities and Exchange Commission (the “SEC”) nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

	Per Share	Total
Public offering price	$	$
Underwriting discounts and commissions(1)	$	$
Proceeds to EnVen Energy Corporation before expenses	$	$

(1) We have agreed to reimburse the underwriters for certain expenses in connection with this offering. See “Underwriting.”

The underwriters have an option to purchase up to an additional             shares of Class A common stock from us at the public offering price, less underwriting discounts and commissions, within 30 days from the date of this prospectus.

The underwriters expect to deliver the shares of Class A common stock to purchasers on or about                 , 2018 through the book-entry facilities of The Depository Trust Company.

Citigroup J.P. Morgan Stifel

BMO Capital Markets

                    , 2018

TABLE OF CONTENTS

	Page
Prospectus Summary		1
Risk Factors		25
Special Note Regarding Forward-Looking Statements		62
Use of Proceeds		64
Capitalization		65
Dividend Policy		67
Dilution		68
Selected Historical Consolidated Financial Data		70
Management’s Discussion and Analysis of Financial Condition and Results of Operations		72
Industry		106
Business		112

	Page
Management		144
Executive Compensation		150
Certain Relationships and Related Party Transactions		157
Principal Stockholders		165
Description of Capital Stock		167
Material U.S. Federal Tax Considerations for Non-U.S. Holders of Common Stock		173
Shares Eligible for Future Sale		176
Underwriting		179
Legal Matters		184
Experts		184
Where You Can Find More Information		184
Index to Consolidated Financial Statements		F-1

We and the underwriters have not authorized anyone to provide you with any information or to make any representations other than those contained in this prospectus or in any free writing prospectuses we have prepared. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may provide you. We are offering to sell, and seeking offers to buy, shares of the Class A common stock only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of the Class A common stock.

Persons who come into possession of this prospectus and any other free writing prospectus in jurisdictions outside the United States are required to inform themselves about and to observe any restrictions as to this offering and the distribution of this prospectus and any such free writing prospectus applicable to that jurisdiction.

Market Data

We use market data and industry forecasts throughout this prospectus, and in particular, in the sections entitled “Prospectus Summary,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business.” Market data used in this prospectus has been obtained from publicly-available information and publications as well as our good faith estimates. We believe that the information contained therein has been obtained from sources believed to be reliable. However, we have not independently verified the data obtained from these sources. Forecasts and other forward-looking information obtained from these sources are subject to the same qualifications and uncertainties that apply to the other forward-looking statements that are described in this prospectus. In addition, while we are not aware of any misstatements regarding the market or industry data presented herein, such statements involve risks and uncertainties and are subject to change based on various factors, including those discussed under the heading “Risk Factors” beginning on page 25 of this prospectus.

Non-GAAP Measures

We believe that the financial data included in this prospectus have been prepared in a manner that complies, in all material respects, with United States (“U.S.”) generally accepted accounting principles (“GAAP”) and are

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consistent with current practice, with the exception of the presentation of certain non-GAAP financial information, such as Adjusted EBITDA and PV-10 (each, as described under the headings “Prospectus Summary—Summary Historical Consolidated Financial Data” and “Prospectus Summary—Summary Historical Reserve and Production Data,” respectively). These are supplemental financial measures that are not prepared in accordance with GAAP. Any analysis of non-GAAP financial measures should be used only in conjunction with results presented in accordance with GAAP.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) adjusted for depreciation, depletion, and amortization (“DD&A”), income tax expense, accretion of asset retirement obligations, non-cash stock-based compensation, interest expense, loss on extinguishment of long-term debt, loss on fair value of 11.00% Senior notes due 2023 (“2023 Notes”), loss (gain) on derivatives, net, cash (paid) received for derivative settlements, net, non-cash interest income and other expenses. Management believes Adjusted EBITDA is useful because it allows management to more effectively evaluate our operating performance and compare to results of operations from period to period and against our peers without regard to our financing methods or capital structure. We adjust net income (loss) for the items listed above to arrive at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet our debt service requirements. A reconciliation of net income (loss) to Adjusted EBITDA is provided in this prospectus under the heading “Prospectus Summary—Summary Historical Consolidated Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA.”

PV-10

Proved, possible and probable reserve PV-10 values are non-GAAP financial measures and represent the period-end present values of estimated future cash inflows from our proved, possible and probable reserves, less future development and production costs, discounted at 10% to reflect timing of future cash flows, using SEC pricing assumptions in effect at the end of the period. Our proved, possible and probable reserve PV-10 values are inclusive of cash inflows from the future net revenues related to third-party production handling agreements, discounted at 10%. The PV-10 value of our proved reserves is equal to standardized measure of discounted future net cash flows at the applicable date, the most directly comparable GAAP financial measure, before deducting future income taxes, discounted at 10%. GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves. Because PV-10 estimates of probable and possible reserves are more uncertain than PV-10 and standardized estimates of proved reserves, but have not been adjusted for risk due to that uncertainty, they may not be comparable with each other. Nonetheless, we believe that PV-10 estimates for reserve categories other than proved present useful information for investors about the future net cash flows of our reserves in the absence of a comparable GAAP measure such as the standardized measure of discounted future net cash flows.

Generally, PV-10 is not equal to, or a substitute for, the GAAP financial measure of standardized measure of discounted future net cash flows. Our proved, possible and probable reserve PV-10 values and standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves. However, our management believes that the presentation of PV-10 is useful because it presents the

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relative monetary significance of our properties regardless of tax structure. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. In addition, investors should be cautioned that estimates of PV-10 for probable and possible reserves, as well as the underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. See “Prospectus Summary—Summary Historical Reserve and Production Data,” “Risk Factors—Risks Related to Our Business—Oil, natural gas and NGL prices are volatile and declines in prices or an extended period of depressed prices will materially adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments” and “Risk Factors—Risks Related to Our Business—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Certain Definitions

As used in this prospectus, unless otherwise noted or the context otherwise requires:

1P. The total amount of proved reserves.

2P. The total amount of proved and probable reserves.

3P. The total amount of proved, probable and possible reserves.

Areal extent. The areal extent of a hydrocarbon-bearing rock (expressed in acres).

Bbl. One stock tank barrel, 42 U.S. gallons liquid volume.

Boe. Barrels of oil equivalent. One Boe is equal to one Bbl, six thousand cubic feet of natural gas, or 42 gallons of natural gas liquids based on approximate energy equivalency.

Boe/d. Barrels of oil equivalent per day.

BOEM. The Bureau of Ocean Energy Management.

Brutus field. The Brutus field is comprised of the U.S. Gulf of Mexico Green Canyon Blocks 158 and 202.

BSEE. The Bureau of Safety and Environmental Enforcement.

Cognac field. The Cognac field is comprised of the U.S. Gulf of Mexico Mississippi Canyon Blocks 150, 151, 194 and 195.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, natural gas or NGLs.

Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

DD&A. Depreciation, depletion, and amortization.

Deepwater. Offshore areas characterized by water depths between 500 feet and 7,500 feet.

Developed acreage. The number of acres allocated or assignable to productive wells or wells capable of production.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas.

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Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Drill well. A project to drill and complete a new wellbore for the purpose of producing oil and natural gas.

Dry hole. Exploratory or development well that does not produce oil and/or natural gas in economically producible quantities.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition, or both.

Full cost method of accounting for oil and natural gas activities. Method of accounting used for oil and natural gas properties, in which all costs associated with exploring for, acquiring and developing oil and natural gas reserves are capitalized.

General and administrative expenses or G&A expenses. The costs incurred for overhead, including compensation, corporate headquarters, software, legal compliance costs and audit and other fees for professional services. Under the full cost method of accounting, the portion of G&A expenses related to acquisition, exploration and development activities are capitalized as oil and natural gas properties.

Glider field. The Glider field is comprised of the U.S. Gulf of Mexico Green Canyon Block 248.

Gross acres. The total acres in which a working interest is owned.

Henry Hub or HH. A widely used benchmark for the pricing of natural gas in the U.S.

Lease operating expenses or LOE. The costs incurred for operating wells and equipment on producing properties, many of which are recurring.

Lobster field. The Lobster field is comprised of the U.S. Gulf of Mexico Ewing Bank Blocks 873, 917 and 963.

MBbls. Thousand barrels of oil or other liquid hydrocarbons. Based on approximate energy equivalency, one MBoe is equal to one MBbl, six MMcf of natural gas, or 42 MGals of NGLs.

MBbls/d. Thousand barrels of oil or other liquid hydrocarbons per day.

MBoe. Thousand barrels of oil equivalent. Based on approximate energy equivalency, one MBoe is equal to one MBbl, six MMcf of natural gas, or 42 MGals of NGLs.

MBoe/d. Thousand barrels of oil equivalent per day.

Mcf. Thousand cubic feet of natural gas. Based on approximate energy equivalency, one MBoe is equal to one MBbl, six MMcf of natural gas, or 42 MGals of NGLs.

MGals. Thousand gallons. Typically used to measure natural gas liquids. Based on approximate energy equivalency, one MBoe is equal to one MBbl, six MMcf of natural gas, or 42 MGals of NGLs.

MMBbl. Million barrels of oil or other liquid hydrocarbons.

MMBoe. Million barrels of oil equivalent.

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MMBtu. Million British Thermal Units. One British Thermal Unit, or Btu, is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

MMcf. Million cubic feet of natural gas.

MMcf/d. Million cubic feet of natural gas per day.

Natural gas liquid(s) or NGL(s). Natural gas liquid or natural gas liquids, which are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane, and natural gasoline that can be collectively removed from produced natural gas, separated into these substances, and sold.

Net pay thickness. The vertical extent of the effective hydrocarbon-bearing rock (expressed in feet).

NYMEX. The New York Mercantile Exchange.

Petronius field. The Petronius field is comprised of the U.S. Gulf of Mexico Vioska Knoll Blocks 742, 786 and 830.

Plugging and abandonment or P&A. The process of sealing off wells, decommissioning platforms and abandoning pipelines.

Possible oil and natural gas reserves. Those additional oil and natural gas reserves that are less certain to be recovered than probable reserves. Refer to Rule 4-10(a)(17) of Regulation S-X as promulgated by the SEC for a complete definition of possible oil and natural gas reserves.

Probable oil and natural gas reserves. Those additional oil and natural gas reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Refer to Rule 4-10(a)(18) of Regulation S-X as promulgated by the SEC for a complete definition of probable oil and natural gas reserves.

Production infrastructure. Various platform, production facilities, and pipelines allowing for the development, production, and transportation of oil and natural gas.

Productive well. A well that is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Proved developed oil and natural gas reserves. Reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Refer to Rule 4-10(a)(6) of Regulation S-X as promulgated by the SEC for a complete definition of proved developed oil and natural gas reserves.

Proved oil and natural gas reserves. The quantities of oil and natural 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. Refer to Rule 4-10(a)(22) of Regulation S-X as promulgated by the SEC for a complete definition of proved oil and natural gas reserves.

Proved undeveloped oil and natural gas reserves or PUDs. Reserves 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. Refer to Rule 4-10(a)(31) of Regulation S-X as promulgated by the SEC for a complete definition of proved undeveloped oil and natural gas reserves.

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Recomplete. Recompletes or recompletion, which means the modification of an existing well for the purpose of producing natural gas and crude oil from a different producing formation.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil or natural gas, or both, that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

SEC pricing. The average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the pricing methodology required by the SEC.

Sidetrack. A secondary wellbore drilled away from the original hole.

Standardized measure of discounted future net cash flows relating to oil and natural gas reserves or Standardized Measure. The present value, discounted at 10%, of future net cash flows from estimated proved reserves calculated using a 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December (with consideration of price changes only to the extent provided by contractual arrangements). The estimated future net cash flows are reduced by projected future development, production (excluding DD&A and impairments of oil and natural gas properties), P&A costs and estimated future income tax expenses.

Ultra deepwater. Offshore areas characterized by water depths greater than 7,500 feet.

Undeveloped acreage. Leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

Unproved properties. Properties with no proved reserves.

West Texas Intermediate or WTI. A widely used benchmark in the pricing of domestic and imported oil in the U.S.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover expense. The costs incurred in connection with major remedial operations on a completed well to restore, maintain or improve the well’s production.

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. Because this is only a summary, it does not contain all of the information that may be important to you. You should read this entire prospectus and should consider, among other things, the matters set forth under “Risk Factors,” “Selected Historical Consolidated Financial Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto appearing elsewhere in this prospectus before making your investment decision. Unless otherwise indicated or the context otherwise requires, references in this prospectus to the “Company,” “we,” “us” and “our” refer to EnVen Energy Corporation, a Delaware corporation, together with its consolidated subsidiaries. References to “EnVen” refer to EnVen Energy Corporation on a standalone basis. See “—Our Organizational Structure” beginning on page 10 of this prospectus for more information regarding our organizational structure.

Our Company

We are an independent oil and natural gas company engaged in the development, exploitation, exploration and acquisition of primarily crude oil properties in the deepwater region of the U.S. Gulf of Mexico. We focus on acquiring and developing operated, deepwater assets that we believe have untapped, lower-risk drill bit opportunities and will provide strong cash flow and significant production potential. This strategy allows us to benefit from the favorable geologic and economic characteristics of the deepwater U.S. Gulf of Mexico fields.

Our portfolio of assets provides us with multiple ways to organically grow our business. Similar to acreage in prolific onshore basins, such as the Permian Basin, much of our acreage is prospective for oil and natural gas production from multiples zones, or stacked-pay, which, using advanced seismic and drilling technology provides us with additional development and production enhancement opportunities within existing and new wellbores. Our portfolio of assets includes multiple years of already identified and potentially high-return projects. These projects include sidetracks, recompletions and new drill wells, most of which are located at or near the production infrastructure we own. In addition, we expect much of our probable and possible reserves will convert to proved reserves through production outperformance, with minimal incremental capital spend.

We have a proven track record of executing transformative, direct negotiated acquisitions, having twice doubled our production and reserves in two asset transactions over the past three years. Targeting assets with quality production infrastructure allows us to further our hub and spoke infrastructure strategy that leverages our abilities to enhance operational efficiency, reduce costs, and increase our third-party production handling revenue through under-utilized processing facilities. Our focus on the deepwater region and our operational efficiency in the region also provides us with opportunities to acquire additional assets that we expect will provide risk-adjusted attractive returns on our investment. We believe these additional opportunities will arise as larger exploration and production companies are expected to continue to divest select under-exploited positions in the deepwater region in order to focus primarily on opportunities in the ultra-deepwater region of the U.S. Gulf of Mexico.

As of June 30, 2018, we held 59 leases in the U.S. Gulf of Mexico spanning approximately 282,789 gross acres (213,914 net), 18 of which have owned and operated offshore platforms and 7 of which have non-operated offshore platforms. Approximately 95% of our proved reserves as of July 31, 2018 and approximately 90% of our average daily production for the six months ended June 30, 2018 was attributable to assets located in the deepwater region. As of June 30, 2018, approximately 78% of our leasehold interests were “held by production,” and we had an average working interest of approximately 80% for our operated fields and approximately 31% for our non-operated fields. For the six months ended June 30, 2018, our daily production averaged 29.5 MBoe/d, approximately 78% of our production was oil, approximately 90% of our revenues were generated from oil production, and approximately 82% of our production was generated by assets we operate. Our average daily production for the first half of 2018 represents an increase of approximately 9% over our average daily

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production of 27.1 MBoe/d for the year ended December 31, 2017. For the year ending December 31, 2018, we expect our average daily production will be between 28 MBoe/d and 32 MBoe/d. Our projected production is based on our cash flows from operating, investing and financing activities, our commodity prices and historical performance of our wells and other management assumptions. As a result, this projection is subject to the risks and uncertainties described in this prospectus under “Special Note Regarding Forward-Looking Statements.” Although we believe we can successfully execute on our exploitation and development projects, risks and uncertainties including those identified in this prospectus under “Risk Factors,” may cause our production results to differ materially from the above projection. For the year ended December 31, 2017, we generated net income and Adjusted EBITDA of $9.0 million and $300.1 million, respectively, and for the six months ended June 30, 2018, we generated net income and Adjusted EBITDA of $3.5 million and $212.2 million, respectively. For the six months ended June 30, 2018, our ratio of Adjusted EBITDA to average daily production was approximately $40/Boe. See “—Summary Historical Consolidated Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA” for a reconciliation of Adjusted EBITDA to net income (loss).

As of July 31, 2018, based on a fully-engineered reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm, we had proved reserves of 56.2 MMBoe, probable reserves of 24.6 MMBoe and possible reserves of 35.2 MMBoe, with approximately 75% of our proved reserves, approximately 66% of our probable reserves and approximately 73% of our possible reserves being considered developed. As of July 31, 2018, the PV-10 value of our proved reserves was $1,178.2 million, the PV-10 value of our probable reserves was $699.6 million, and the PV-10 value of our possible reserves was $754.0 million. The PV-10 values in our July 31, 2018 reserve report are net of the estimated PV-10 costs associated with our future expected P&A liabilities. As of July 31, 2018, our proved reserves represent a reserve replacement of approximately 142% from December 31, 2017 at a finding, development and acquisition cost of approximately $9.50/Boe. See “—Summary Historical Reserve and Production Data—Non-GAAP Financial Measures—PV-10” for a reconciliation of the PV-10 value of our proved reserves to the Standardized Measure.

Our Assets and Reserves

The following table presents our oil, natural gas and NGL estimated reserves quantities and PV-10 values as of July 31, 2018, based on a fully-engineered reserve report prepared by NSAI, an independent petroleum engineering firm. In addition, the table shows our average daily production and oil production percentages for certain fields for the six months ended June 30, 2018.

	Average Daily Production for the six months ended June 30, 2018					Proved Reserves						Probable Reserves						Possible Reserves
	(Boe/d)		% Oil			Total (MMBoe)			PV-10(1)(2) (In millions)			Total (MMBoe)			PV-10(2) (In millions)			Total (MMBoe)			PV-10(2) (In millions)
Brutus field		8,709		77	%		18.7		$	364.2			5.3		$	177.0			7.3		$	165.3
Glider field		6,296		88	%		8.4			306.4			5.1			193.7			3.6			118.8
Lobster field		4,165		86	%		8.5			196.1			5.6			144.3			10.8			233.7
Petronius field		3,306		75	%		5.1			110.7			2.3			49.5			2.8			49.2
Cognac field		1,067		74	%		3.7			77.3			2.0			36.6			4.2			45.3
Other fields		5,922		67	%		11.8			102.8			4.3			84.5			6.5			107.4
Production handling agreements(3)		—		—			—			20.7			—			14.0			—			34.3
Total		29,465		78	%		56.2		$	1,178.2			24.6		$	699.6			35.2		$	754.0
Percentage developed reserves							75	%		81	%		66	%		63	%		73	%		72	%

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(1) Proved reserve PV-10 value is a non-GAAP measure and differs from the Standardized Measure, the most directly comparable GAAP financial measure, because the proved reserve PV-10 value does not include the effects of income taxes on future net revenues, discounted at 10%, but includes the future net revenues from production handling agreements, discounted at 10%. Neither the proved reserve PV-10 value nor the Standardized Measure represents the fair value of our proved oil, natural gas and NGL reserves. See “—Summary Historical Reserve and Production Data—Non-GAAP Financial Measures—PV-10” for a reconciliation of our proved reserve PV-10 value to the Standardized Measure.

(2) The PV-10 value of our proved reserves is presented net of the estimated costs associated with our future expected P&A liabilities with a PV-10 of approximately $152.9 million. Our probable and possible reserve PV-10 values do not have any associated incremental future expected P&A liabilities; however, the estimated timing of when the P&A liabilities will be incurred could be delayed by the probable and possible incremental production volumes.

(3) Production handling agreements relate to estimated future net revenues contracted with third parties under certain contractual arrangements. The PV-10 values vary by reserve category based on NSAI’s assumption for contract termination. Under existing agreements as of July 31, 2018, $20.7 million is expected to be received through December 31, 2020; an additional $14.0 million is expected to be received through December 31, 2024; and an additional $34.3 million is expected to be received through December 31, 2028.

In the past, we have frequently been able to outperform our initial proved reserve estimates, with actual production quantities and PV-10 values exceeding those originally represented in our third-party reserve reports. Because SEC methodology for booking proved reserves limits to the lowest known hydrocarbon volumes in a wellbore and requires a 90% likelihood of ultimate production, it is common for deepwater U.S. Gulf of Mexico fields to have actual outcomes that exceed the initial proved reserve booking. As an example, our July 31, 2018 reserve report estimates that the Lobster, Petronius and Neptune fields purchased from Marathon in December 2015 will outperform the proved reserve estimates made at the time of the acquisition. Eliminating all reserve additions resulting from capital projects, our July 31, 2018 reserve report estimates an increase in proved reserves of approximately 6 MMBoe (approximately 40%) from the December 31, 2015 reserve report. We believe our history of outperforming initial proved reserve bookings substantiates our high-quality assets and our technical team’s ability to consistently evaluate and execute commercial projects successfully.

We have a substantial project inventory with unbooked hydrocarbon resources under and adjacent to our current production infrastructure and approximately 50% of our planned 2018 and 2019 capital expenditures are dedicated to developing these unbooked resources. In June 2018, we discovered over 350 feet of net pay sands in multiple intervals at our Lobster A-2 well, the majority of which is beneath the field’s current production zones. These results are evidence of our projects with unbooked resources as these deeper intervals represent significant potential reserves that are currently not included in our reserve report. Including these Lobster field projects, we have identified over 80 projects on our existing acreage that we expect will provide significant reserves to potentially add. Out of these identified projects, many have been partially de-risked due to the interpretation of recent proprietary 3-D seismic data and information obtained from previously drilled nearby wells that are comparable to the objective intervals of our projects. Moreover, we expect the vast majority of these projects to be drilled directly from our platform infrastructure or the projects are within relatively short distances from our infrastructure, which would allow for shorter development and production lead times should reserves be discovered.

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Our Capital Program

Our capital programs for 2018 and 2019 consist of capital expenditures in 2018 of $200 million to $250 million and capital expenditures in 2019 of $275 million to $325 million, both years exclusive of nominal annual P&A expenditures of less than $30 million. As part of our 2018 and 2019 capital programs we expect to conduct approximately 21 sidetracks and 6 recompletions of existing wells and drill five new wells. As of July 31, 2018, we have completed five of these sidetracks and two recompletes. These capital programs are primarily focused on the continued development of our operated Brutus, Glider, Lobster and Cognac fields, accounting for approximately 72% and 60% of our total 2018 and 2019 capital programs, respectively. In addition, our 2018 and 2019 capital programs allocate approximately 1% and 27%, respectively, for subsea tieback projects at certain of our operated fields, approximately 19% and 11%, respectively, for other capital projects at either properties we own or items we control, and approximately 8% and 1%, respectively, for non-operated drill wells and recompletions. We estimate that our 2018 and 2019 capital programs have the potential to substantially increase our reserves for the years ended December 31, 2018 and 2019 and contribute approximately 14 MBoe/d to 18 MBoe/d to our 2019 year end exit rate daily production. Of the approximate 32 projects in our 2018 and 2019 capital programs, approximately 15 target objectives with unbooked hydrocarbon resources remain to be drilled and completed. See “Business—Our Oil and Natural Gas Properties—Producing Properties and Related Projects” for a discussion of the current and planned projects at our Brutus, Glider, Lobster and Cognac fields.

The projected production from our capital programs is based on our cash flows from operating, investing and financing activities, our commodity prices and historical performance of our wells and other management assumptions. As a result, this projection is subject to the risks and uncertainties described in this prospectus under “Special Note Regarding Forward-Looking Statements.” Although we believe we can successfully execute on our exploitation and development projects, risks and uncertainties, including those identified in this prospectus under “Risk Factors,” may cause our production results to differ materially from the projections above.

The ultimate amount of capital that we expend may fluctuate materially based on market conditions and drilling results and is subject to the discretion of our management and board of directors. As approximately 96% of our expected 2018 and 2019 capital program expenditures are for projects and items that we operate, we have increased control over our overall budget and expenditures in connection with our capital program. We do not expect to incur any additional debt or use proceeds from this offering to fund our 2018 and 2019 capital programs but instead expect, assuming current oil and natural gas prices, to fully fund the programs with cash on hand and internally generated cash flows.

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U.S. Gulf of Mexico Overview

The U.S. Gulf of Mexico covers the area from Texas to Florida. Offshore activities in the U.S. Gulf of Mexico are typically classified based upon the drilling depth, which are organized into three categories: (i) the shelf, covering the shallow waters of the outer continental shelf in depths less than 500 feet; (ii) the deepwater, characterized by water depths between 500 feet and 7,500 feet and marking the transition from the shallow water associated with the shelf to the deeper water environment, and (iii) the ultra-deepwater, covering all depths greater than 7,500 feet. Unlike the current production generated in the shallow waters of the shelf, reservoirs in deepwater U.S. Gulf of Mexico are largely oil-dominant.

The U.S. Gulf of Mexico area is one of the nation’s largest producing oil regions and is an integral part of the U.S. energy industry. According to the Energy Information Administration (the “EIA”), crude oil production from the offshore U.S. Gulf of Mexico has increased annually every year since 2013 and reached 1.65 million barrels per day in 2017, the highest annual level on record. Additionally, federal offshore crude oil production accounted for approximately 17% of total U.S. crude oil production in 2017, second only to production from the Permian Basin. The U.S. Gulf of Mexico, like the oil industry itself, is cyclical by nature. Recently, after the lifting of the drilling moratorium in 2011, exploration and production companies resumed their exploration and development activity in the deepwater and ultra-deepwater regions of the U.S. Gulf of Mexico.

Source: EIA

Given the significant historical production in the region and long history of operations over the past 40 years, an extensive network of platform and pipeline infrastructure has been developed on the continental shelf for the production, processing and export of oil and natural gas. Over 45% of total U.S. petroleum refining capacity was located along the U.S. Gulf of Mexico, along with approximately 51% of the U.S. natural gas processing plant capacity. The extensive network of midstream and downstream infrastructure allows U.S. Gulf of Mexico production to receive attractive pricing due to its proximity to demand centers and the optionality available from multiple end markets. In addition, the substantial pipeline, terminal and storage infrastructure along the U.S. Gulf of Mexico provide attractive pricing for the export of oil and natural gas production.

The commerciality of fields in the deepwater U.S. Gulf of Mexico is generally dependent on water depth, oil and natural gas prices, size of resource and the availability of existing pipeline infrastructure and hub processing facilities in the area. In response to the oil price collapse in 2014, operators have increasingly focused on decreasing operating costs and exploiting new technologies to improve economics and reduce exploration risk. One way to accomplish this is to focus on near-infrastructure projects, which have substantially better field economics due to lower capital costs and a decreased lag time from discovery to first production than new play exploration projects. Advancements in seismic imaging technology and increased utilization of predictive data analytics have also lead to smarter well placement, better well design and significant operational efficiencies that have ultimately reduced risks and increased drilling and development success rates in recent years. The commercial availability of wide-azimuth

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3-D seismic data has provided more accurate images than were possible before, and has meaningfully enhanced the quality of data used to identify previously unknown or uneconomic prospects.

In recent years, a number of independent operators, including ConocoPhillips, Marathon Oil, Freeport-McMoRan, and Apache have either abandoned their U.S. Gulf of Mexico programs altogether or divested assets. Of the large operators that remain active in the U.S. Gulf of Mexico, many have responded by focusing on a few large high-impact ultra-deepwater projects. Additionally, we believe that some large operators are motivated to accelerate the divestiture of select under-exploited deepwater assets. We intend to focus on the deepwater region for near-term acquisitions in order to capitalize on the opportunities created by current market conditions.

Our Acquisition History and Opportunity

We have a proven track record of accretive acquisitions and we will continue to proactively seek to acquire what we believe to be under-exploited deepwater assets. In December 2015, we approximately doubled our production and proved reserves through a transaction with Marathon Oil Corporation (“Marathon”). In December 2016, we again approximately doubled our production and proved reserves through a transaction with Shell Offshore Inc. (“Shell”). Both asset transactions were direct negotiations with the respective sellers and each required approximately two years from initial expression of interest to the closing of the acquisition. The assets purchased from Marathon were acquired for an estimated $6.53/Boe for proved developed producing reserves and the cumulative net cash flow of the acquired fields exceeded the effective purchase price within 16 months of the acquisition closing date, with greater than 65% of 1P PV-10 value remaining as of December 31, 2017. The assets purchased from Shell were acquired for an estimated $8.21/Boe for 1P reserves and the cumulative cash flow, less capital expenditures, of the acquired fields equaled 58% of the effective purchase price on December 31, 2017, one year after the acquisition closing date.

We believe that additional opportunities exist in the market today in the deepwater region of the U.S. Gulf of Mexico as companies prioritize their asset portfolios including larger operators choosing to focus on larger, more capital-intensive projects in the ultra-deepwater or companies electing to divest their U.S. Gulf of Mexico asset portfolio. Since the closing of the Shell acquisition in December 2016, we have reviewed approximately 20 potential acquisitions under non-disclosure agreements. We are proactively pursuing acquisitions of assets that in general (i) have proved developed producing reserves with further development and exploitation potential, particularly assets where our multidisciplinary technical team believes have unbooked hydrocarbon resources, (ii) have oil-weighted production, (iii) have operated assets that allow us to control operating costs, project selection, timing and costs, and the ultimate timing and costs of P&A liabilities, (iv) have accompanying infrastructure for offtake and processing, or which leverage our existing infrastructure, and (v) have the potential to be direct-negotiated transactions. We believe we are favorably positioned in the market to execute on expected future acquisitions as the industry in the U.S. Gulf of Mexico consolidates.

Our Competitive Strengths

We have a number of competitive strengths that we believe will allow us to execute our business strategies successfully and achieve our primary business objectives, including:

• High-quality, oil-focused and producing deepwater asset base. The high-quality and low risk nature of our assets provides us with a number of competitive advantages, namely a lower risk profile with significant additional development and exploration potential, reliable cash flows from long-life, lower-decline producing reserves and an opportunity to leverage the infrastructure we own to lower operating and development costs. For the three year period ended December 31, 2017, our all-in average finding, development and acquisition cost was approximately $10/Boe. In addition, we believe that much of our acreage is prospective for oil and natural gas production from multiples zones, or stacked-pay, which

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provides us with additional development and production enhancement opportunities within existing and future wellbores. Our Lobster A-2 well, which targeted six pay zones, is an example of the stacked-pay potential of many of our properties. Our producing assets are also heavily oil-weighted. Approximately 79% of our total proved reserves, as of July 31, 2018, and approximately 78% of our daily average production for the six months ended June 30, 2018, consisted of oil. The oil-weighted nature of our reserves and production, and our proximity to infrastructure in the U.S. Gulf of Mexico, allows us to benefit from attractive realized pricing, especially relative to that received currently by producers in many onshore basins such as the Permian Basin. For the year ended December 31, 2017, our Adjusted EBITDA margin and net income margin were approximately 69% and approximately 2%, respectively. For the six months ended June 30, 2018, our Adjusted EBITDA margin and net income margin were approximately 69% and approximately 1%, respectively. See “—Summary Historical Consolidated Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA” for a reconciliation of Adjusted EBITDA to net income (loss).

• Ownership of extensive deepwater infrastructure. We own and operate a portfolio of geographically dispersed production facilities in the deepwater region of the U.S. Gulf of Mexico that affords us operational differentiation and opportunity access. We estimate that the deepwater infrastructure that we now own cost the original owners approximately $4 billion to construct and put into service. The development of assets drilled or accessible from our platforms allows us to achieve enhanced returns and greater cost efficiencies and reduce the time to initiate production after completing rig operations on a well. For drilling and well work conducted from a platform, we utilize platform drilling rigs that are less expensive to operate than floating drilling rigs, which allows us to achieve lower average project costs. In recent U.S. Gulf of Mexico lease sales, we acquired primary term lease blocks near our production facilities. These leases contain potential exploration opportunities we may elect to pursue, which if successful, would tie back to our facilities. Additionally, each of our deepwater production facilities has underutilized processing capacity. We use the capacity to generate additional revenue by offering third-party production processing services, which require minimal incremental operating expenditures by us. We currently have eight production handling agreements in place that generated $14.8 million of additional revenue during the year ended December 31, 2017.

• Multi-year inventory of attractive lower-risk drill bit projects. Our geological and geophysical professionals have identified more than 80 growth projects across our portfolio that we believe represent multiple years of inventory of lower geologic risk development and exploration opportunities. The number of independent projects in our project inventory allows us to review and prioritize the projects that we select to conduct. During the six months ended June 30, 2018, we operated multi-project development programs at our Brutus and Lobster fields. For the remainder of 2018 and 2019, we will focus our capital programs on the continued development of our operated Brutus, Glider, Lobster and Cognac fields. We expect that these multi-project programs will enable us to grow production and reserves while achieving cost and other efficiencies. Our extensive library of proprietary 3-D seismic data allows us to compare attributes of potential projects to those of known successful commercial discoveries. We believe this data reduces the geologic risk and increases the drilling success rate of our projects. We expect to be able to expand our existing project inventory with periodic field reviews, acreage obtained through lease sales and farm-in arrangements with other companies.

• Experienced and safe deepwater operator with operating control over a majority of our assets. We operate properties that generated approximately 82% of our production for the six months ended June 30, 2018 and accounted for approximately 86% of our proved reserves as of July 31, 2018. Approximately 96% of our expected capital expenditures for 2018 and 2019 are allocated to projects at either properties that we operate or items that we control. Operational control allows us to dictate the selection and pace of drilling projects, have direct control over operating costs, manage the timing and costs of our P&A liabilities, institute our safety and environmental programs and practices and more closely control risks. By following our disciplined approach to minimize expenses, after taking over the

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operations at the Brutus and Glider fields on December 30, 2016, we successfully reduced the annual operating costs for these fields by approximately 42% for the year ended December 31, 2017 compared to the year ended December 31, 2016. The reduced operating costs resulted from multiple actions including modifying transportation logistics and implementing multi-functional job duties. During this same period, our company-wide total reportable incident rate decreased by approximately 40% and for 2017 was approximately 64% below the published industry rate. In April 2018, in recognition of our culture of safety, we received the prestigious 2018 National Ocean Industries Association Safety in Seas Culture of Safety Award.

• Veteran senior management team with substantial U.S. Gulf of Mexico deepwater industry and technical expertise. Our senior management team has, on average, over 25 years of industry experience and has extensive expertise in deepwater geology, geophysics, drilling, well-completion, facility operations and regulatory compliance. Our senior management team collectively has executed over $25 billion of energy M&A transactions and includes members who have previously taken several energy companies public. Because of our management team’s significant operating and acquisition history as well as its experience and familiarity with the U.S. Gulf of Mexico, we believe we have a competitive advantage in sourcing and executing on attractive acquisition targets. Additionally, our senior management team has implemented governance practices appropriate for a public company.

• Strong financial position and disciplined hedging program. We pursue a disciplined financial policy with the objective of maintaining conservative leverage, strong asset coverage and ample liquidity. During the year ended December 31, 2017, we generated significant cash flow, which we used to reduce our total debt by 23.8% from $390.5 million to $297.5 million. As of June 30, 2018, the ratio of our total debt to Adjusted EBITDA for the last 12 months ended June 30, 2018 was 1.0x. See “—Summary Historical Consolidated Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA” for a reconciliation of Adjusted EBITDA to net income (loss). As of June 30, 2018, our cash balance and availability under our undrawn Revolving Credit Facility (after giving effect to $3.6 million of outstanding letters of credit), subject to the borrowing base of $275.0 million at the time, was $362.9 million. Importantly, we expect to fully fund our current capital programs, assuming current oil and natural gas prices, with cash on hand and internally generated cash flows. Our predominantly fixed cost structure results in high rates of cash flows from increases in realized oil and natural gas prices being converted into Adjusted EBITDA. In the future years, we plan to fund annual capital expenditures at levels that allow us to grow production while generating positive cash flow. We also maintain an active commodity hedging program to protect our balance sheet and preserve returns on our investments from a potential decline in oil and natural gas prices, while also maintaining some upside participation in the event oil and natural gas prices rise. During the six months ended June 30, 2018, we recognized a loss of $37.6 million on our derivatives primarily due to an increase in the future commodity price outlook during the six months ended June 30, 2018.

Our Business Strategy

Our primary business objective is to provide attractive returns on invested capital while increasing reserves, production and cash flow. We intend to achieve this objective by executing the following strategies:

• Identify and execute drill bit opportunities in existing, adjacent and acquired deepwater assets. We expect to increase our production and revenue by executing projects from our existing drill bit inventory. We believe that our inventory of identified drill bit development and exploitation projects in and adjacent to our producing fields includes projects that meet our investment criteria and risk parameters for years to come. In addition, we utilize our extensive library of proprietary 3-D seismic data and local operational knowledge to identify and reduce the technical risk of potential future projects. As a result of owning considerable existing infrastructure assets, including production platforms and processing facilities, we opportunistically seek to obtain economic interests in

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development and exploration projects owned by other companies. We expect to fully fund our current capital programs, assuming current oil and natural gas prices, with cash on hand and internally generated cash flows.

• Leverage existing infrastructure and enhance operating efficiencies. We own and operate a large network of offshore platforms and processing facilities centered around our current producing properties that were constructed by the original owners for approximately $4 billion. Each of our deepwater platforms has available processing capacity that we plan to utilize by (i) executing our capital programs and bringing additional production online, (ii) targeting acquisitions of third-party assets and acreage available in lease sales that are accessible from our infrastructure and (iii) offering processing handling services to nearby third-party operators. This infrastructure-led growth strategy enables us to greatly reduce development costs while significantly reducing the cycle times between discovery and production. Importantly, technical improvements have allowed the industry to continue to expand the radius of potential tiebacks, making our infrastructure more valuable. In addition, our production handling agreements represent significant incremental revenue at no incremental cost to us. All of these activities help us to extend the useful life of our facilities and defer future abandonment liabilities.

• Opportunistically execute accretive acquisitions. We have a proven track record of successfully completing accretive M&A transactions with some of the largest deepwater operators, like Marathon and Shell, which we believe positions us favorably for future deals. We believe there is an emerging void in independent deepwater operators that we expect to be able to capitalize upon, and that opportunities exist to grow our business selectively through focused and strategic asset acquisitions that will provide attractive risk-adjusted returns.

• Conduct business in a safe and environmentally sensitive manner. Conducting our business in a safe and environmentally prudent manner sets the tone for our overall business performance. As such, we adhere to a strict corporate protocol of safety and environmental standards that govern our operations. In April 2018, we received the prestigious 2018 National Ocean Industries Association Safety in Seas Culture of Safety Award in recognition of the culture of safety that we have instituted while safely increasing our production and reserves and reducing operating costs.

• Maintain conservative balance sheet leverage and robust liquidity. We intend to limit our total debt and maintain robust liquidity. Additionally, we expect to maintain a hedging program that protects cash flows and allows us to fund capital plans through commodity cycles. While we seek to maintain a disciplined financial strategy with a conservative leverage profile, we may selectively choose to temporarily increase our leverage in order to pursue accretive transformative and/or complementary asset acquisitions. In these instances, we would expect to protect our investment returns and our balance sheet with an active hedging program.

• Proactively manage our P&A obligations and bonding requirements. As of July 31, 2018, approximately 91% of our proved reserves were located in our U.S. Gulf of Mexico deepwater fields, which are comprised of long-life, lower-decline producing reservoirs. Additionally, since we operated approximately 86% of our proved reserves as of July 31, 2018, we are able to manage the majority of our P&A obligations. Therefore, the majority of our recent and near-term P&A obligations relate to a small number of shallow water platforms. During 2017, we abandoned six legacy shallow water platforms, which were located on fields that had reached their economic life. We currently expect to spend less than $30 million per year in 2018 and 2019 to plug and abandon additional shelf fields that have reached the end of their economic life. Given the long remaining life of our deepwater fields, we do not anticipate any P&A expenditures related to our deepwater facilities before 2025, based on the proved reserve estimates in our July 31, 2018 reserve report. The PV-10 value of our proved reserves in our reserve report as of July 31, 2018 is presented net of the estimated costs associated with our future

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expected P&A liabilities with a PV-10 of approximately $152.9 million. As of June 30, 2018, we had approximately $150 million in place to offset the ultimate P&A obligations associated with our previous asset acquisitions. We intend to increase this amount, which consists of cash collateral for P&A bonds, cash escrow and note receivables from prior asset owners, to approximately $205 million, as we fund additional cash escrow with a percentage of net revenue from our Lobster, Petronius, and Neptune fields related to the acquisition of these assets from Marathon. Additionally, the Bureau of Ocean Energy Management (“BOEM”) and certain third parties require us to post supplemental and performance bonds as a means to ensure our decommissioning obligations. As of June 30, 2018, we were in compliance with these requirements and met all of our outstanding abandonment bonding demands.

Our Organizational Structure

EnVen is a holding company, and currently its sole material asset is an 89% economic equity ownership interest in Energy Ventures GoM LLC, a Delaware limited liability company (“EnVen GoM”). EnVen operates and controls all of the business and affairs and consolidates the financial results of EnVen GoM, and its only business is to act as sole manager of EnVen GoM. EnVen Equity Holdings, LLC (“EnVen Equity Holdings”) currently holds an 11% economic equity ownership interest in EnVen GoM. Equity ownership percentages reflect the outstanding preferred equity of EnVen GoM, which will be converted to shares of Class A common stock in connection with this offering.

The diagram below depicts our organizational structure and equity ownership percentages after giving effect to this offering and conversion of Series A preferred stock into Class A common stock in connection with this offering.

The Class B common stock held by EnVen Equity Holdings, and indirectly held by its members, provides no economic interests in EnVen (where “economic interests” means the right to receive any distributions or dividends, whether cash or stock, in connection with common stock). As a result, the members of EnVen Equity Holdings hold their economic interest in us entirely through indirect ownership in the limited liability company units of EnVen GoM (“LLC Units”). Holders of the LLC Units may, at any time, require EnVen GoM to repurchase all or any number of its LLC Units for consideration equal to one share of Class A common stock per LLC Unit repurchased (or cash at our election) under certain circumstances. However, with approval of our board of directors, we may cause such obligation to be satisfied by exercising an option to purchase such LLC Units for a cash price equal to the fair value of one share of Class A common stock or by issuing newly issued shares of Class A common stock, in each case, as specified in EnVen GoM’s Second Amended and Restated

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Limited Liability Company Agreement (the “EnVen GoM LLC Agreement”). See “Description of Capital Stock” for more information about our certificate of incorporation and the terms of the Class A common stock and Class B common stock. See “Certain Relationships and Related Party Transactions” for more information about the EnVen GoM LLC Agreement, including the terms of the LLC Units and the redemption right of EnVen Equity Holdings.

Implications of Being an Emerging Growth Company

As a company with less than $1.07 billion in revenue during our last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), which was enacted in April 2012. An “emerging growth company” may take advantage of exemptions from some of the reporting requirements that are otherwise applicable to public companies that are not emerging growth companies. These exemptions include:

• being permitted to present only two years of audited consolidated financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in this prospectus;

• not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, as amended (the “Sarbanes-Oxley Act”), in the assessment of our internal control over financial reporting;

• reduced disclosure obligations regarding executive compensation in our periodic reports, proxy statements and registration statements; and

• exemption from the requirements of holding a nonbinding advisory vote on executive compensation and obtaining stockholder approval of any golden parachute payments not previously approved.

We may take advantage of these reporting exemptions until we are no longer an emerging growth company. We will remain an emerging growth company until the last day of our fiscal year following the fifth anniversary of the completion of this offering. However, if certain events occur prior to the end of such five-year period, including, but not limited to, if we become a “large accelerated filer,” or if our annual gross revenue exceeds $1.07 billion or we issue more than $1.0 billion of non-convertible debt in any three-year period, we will cease to be an emerging growth company prior to the end of such five-year period.

We have elected to take advantage of certain of the reduced disclosure obligations in the registration statement of which this prospectus is a part and may elect to take advantage of some, but not all, of the reduced reporting requirements in future filings. As a result, the information that we provide to our stockholders may be different than what you might receive from other public reporting companies in which you hold equity interests.

In addition, the JOBS Act provides that an emerging growth company can take advantage of an extended transition period for complying with new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably elected not to avail ourselves of this exemption and, therefore, we will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

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Company Information

EnVen Energy Corporation, the issuer of the Class A common stock in this offering, was originally formed as a limited liability company on June 13, 2014, and was converted to a corporation in the state of Delaware on November 4, 2015. Our principal office is located at 333 Clay Street, Suite 4200, Houston, TX 77002 and our telephone number is 713-335-7000. Our website is www.enven.com. Information on, or accessible through, our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

Risks Related to Our Business

Investing in our Class A common stock involves substantial risk. You should carefully consider all of the information in this prospectus prior to investing in our Class A common stock. There are several risks related to our business and our ability to leverage our strengths described in the “Risk Factors” section and elsewhere in this prospectus. Among these important risks are the following:

• oil, natural gas and NGL prices are volatile and declines in prices or an extended period of depressed prices will materially adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments;

• if oil, natural gas and NGL prices are depressed or decrease, we may be required to record write-downs of the carrying value of our oil and natural gas properties;

• our derivative activities could result in financial losses or could reduce our earnings;

• we may be unable to make attractive acquisitions or successfully integrate acquired businesses or properties, and any inability to do so may hinder our ability to grow and could materially adversely affect our results of operations, financial position and cash flows;

• we may incur losses as a result of title defects in the properties in which we invest;

• our exploitation, development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow reserves;

• drilling for and producing oil and natural gas are high risk activities with many uncertainties that could result in a total loss of investment or otherwise materially adversely affect our business, financial condition or results of operations; and

• reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

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THE OFFERING

Class A common stock offered by us                 shares.

Option to purchase additional shares We have granted the underwriters an option to purchase up to an additional             shares of Class A common stock for 30 days from the date of this prospectus.

Class A common stock outstanding after this offering             shares (or     , if all outstanding LLC Units in EnVen GoM held by EnVen Equity Holdings are exchanged for newly-issued shares of Class A common stock on a one-for-one basis).

If the underwriters exercise their 30-day option to purchase additional shares of Class A common stock in full,             shares (or     , if all outstanding LLC Units in EnVen GoM held by EnVen Equity Holdings are exchanged for newly-issued shares of Class A common stock on a one-for-one basis) would be outstanding.

Ratio of shares of Class A common stock to LLC
Units
Our amended and restated certificate of incorporation and the EnVen GoM LLC Agreement require that we at all times maintain a one-to-one ratio between the number of shares of Class A common stock issued by us (subject to certain exceptions for treasury shares and shares underlying certain convertible or exchangeable securities) and the number of LLC Units owned by us, as well as a one-to-one ratio between the number of shares of Class B common stock owned by EnVen Equity Holdings and the number of LLC Units owned by EnVen Equity Holdings. This construct results in EnVen Equity Holdings having a voting interest in us that is substantially the same as EnVen Equity Holdings’ percentage economic interest in EnVen GoM.

Voting Rights Holders of our Class A common stock and Class B common stock will vote together as a single class on all matters presented to stockholders for their vote or approval, except as otherwise required by applicable law or provided by our certificate of incorporation or bylaws. Each share of Class A common stock will entitle its holder to one vote per share on all such matters, and each share of Class B common stock entitles its holder to one vote per share on all such matters. See “Description of Capital Stock.”

Voting power held by holders of Class A common stock after giving effect to this offering
    % (or     %, if all outstanding LLC Units in EnVen GoM held by EnVen Equity Holdings are exchanged for newly-issued shares of Class A common stock on a one-for-one basis).

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Voting power held by holders of Class B common stock after giving effect to this offering
    % (or 0.00%, if all outstanding LLC Units in EnVen GoM held by EnVen Equity Holdings are exchanged for newly-issued shares of Class A common stock on a one-for-one basis).

Use of proceeds We estimate that the net proceeds to us from this offering will be approximately $         million, after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us. We intend to use the net proceeds from this offering to purchase                 LLC Units directly from EnVen GoM at a price per unit equal to the initial public offering price per share of Class A common stock in this offering less the underwriting discounts and commissions. EnVen GoM will use the proceeds from the sale of LLC Units to redeem up to 35% of the aggregate principal amount of the 2023 Notes at a redemption price equal to 111.0% of the 2023 Notes to be redeemed plus accrued and unpaid interest, pursuant to the terms of the indenture governing the 2023 Notes. As of June 30, 2018, $325 million of the 2023 Notes were outstanding. The 2023 Notes have a stated maturity of February 15, 2023 and accrue interest at a rate equal to 11.0% per annum. We intend to use any remaining proceeds from this offering for general corporate purposes, including to expand our current business through acquisitions of, or investments in, other businesses, products or technologies. However, we have no commitments with respect to any such acquisitions or investments at this time. See “Use of Proceeds.”

Dividend policy Following our initial public offering, we will consider paying a cash dividend on our Class A common stock. Any decision relating to the declaration, amount and payment of any future dividends on shares of Class A common stock is at the sole discretion of our board of directors. In the event we decide to pay dividends in the future, our ability to pay dividends may be limited by covenants in our Revolving Credit Facility and the indenture governing our 2023 Notes. See “Dividend Policy.”

Tax Receivable Agreement Pursuant to the terms of the EnVen GoM LLC Agreement, the members of EnVen GoM have the right to redeem the LLC Units for cash payment equal to the fair value of our Class A common stock, or at our option, for our Class A common stock (the “Redemption Rights”). When a holder of LLC Units exercises such right to have its LLC Units redeemed or, at our election, exchanged, the redeeming holder will receive cash or shares of our Class A common stock, from which we may obtain an increase in our share of the tax basis of the assets of EnVen GoM (a “Basis Adjustment”). A Basis Adjustment may have the effect of reducing the amounts that we would otherwise pay in the future to various tax authorities. The Basis Adjustments may also decrease gains (or increase losses) on future dispositions of certain capital assets to the extent tax basis is allocated to those capital assets. We are party to the Tax Receivable Agreement (as

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defined below) with EnVen GoM and EnVen Equity Holdings for the benefit of the members of EnVen Equity Holdings. The Tax Receivable Agreement provides for the payment by us to such holders of 85% of the amount of tax benefits, if any, that we actually realize, or in some circumstances are deemed to realize, as a result of any Basis Adjustment or any other increases in the tax basis of the assets of EnVen GoM attributable to payments made under the Tax Receivable Agreement and deductions attributable to imputed interest and other payments of interest pursuant to the Tax Receivable Agreement. We will benefit from the remaining 15% of tax benefits, if any, that we may actually realize. The Tax Receivable Agreement will remain in effect until the earlier of (a) EnVen Equity Holdings or any successor holders exchange all LLC Units of EnVen GoM pursuant to the Redemption Rights and the payment of all amounts required to be paid under the Tax Receivable Agreement and (b) the Tax Receivable Agreement is terminated pursuant to its terms. We cannot be certain at this time when EnVen Equity Holdings may elect to convert its interests into shares of our Class A common stock. For more information on the Tax Receivable Agreement, see “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

Proposed NYSE symbol “ ENVN”

Risk factors See “Risk Factors” beginning on page 25 of this prospectus for a discussion of factors you should carefully consider before deciding to invest in our Class A common stock.

Unless we specifically state otherwise, all information in this prospectus, except for our historical financial statements included elsewhere in this prospectus, assumes the consummation of a stock split immediately prior to the completion of this offering pursuant to which each share of Class A common stock and Class B common stock held of record by the holder thereof will be exchanged into                  shares of Class A common stock and Class B common stock, respectively (the “Stock Split”).

Unless we specifically state otherwise, throughout this prospectus the number of shares of our Class A common stock to be outstanding after completion of this offering is based on                  shares outstanding as of                  , 2018 and                 additional shares of our Class A common stock issuable upon the automatic conversion of all outstanding shares of our Series A Convertible Perpetual Preferred Stock (the “Series A preferred stock”) upon the closing of this offering.

The number of shares of our Class A common stock to be outstanding after this offering excludes:

•             shares of Class A common stock issuable upon the exercise of options outstanding as of                  , 2018 at a weighted average exercise price of $                per share;

•             shares of Class A common stock issuable upon exchange of LLC Units in EnVen GoM held by EnVen Equity Holdings;

•             shares of Class A common stock issuable upon exercise of the warrants outstanding as of June 30, 2018 at a weighted average exercise price of $        per share;

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•             shares of Class A common stock reserved for future issuance under our EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan (the “2015 Plan”); and

•              shares of Class A common stock issuable upon the vesting and settlement of outstanding restricted stock units previously issued, or to be issued upon the consummation of this offering, under the 2015 Plan.

Unless we specifically state otherwise, all information in this prospectus assumes:

• the automatic conversion of all outstanding shares of our Series A preferred stock into                 shares of our Class A common stock, which will occur immediately prior to the closing of this offering;

• no exercise of any of the outstanding warrants;

• no exercise of the option to purchase additional shares of Class A common stock by the underwriters; and

• the filing of our amended and restated certificate of incorporation and the adoption of our amended and restated bylaws immediately prior to the closing of this offering.

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SUMMARY HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table sets forth our summary historical consolidated financial data for the periods and as of the dates indicated. The summary consolidated financial data as of and for each of the fiscal years ended December 31, 2017 and 2016 have been derived from our audited consolidated financial statements included elsewhere in this prospectus. The summary consolidated balance sheet data as of June 30, 2018 and the summary consolidated statement of operations data, statement of cash flows data and other financial data for each of the six months ended June 30, 2018 and 2017 have been derived from our unaudited consolidated financial statements, which have been prepared on a basis consistent with the audited consolidated financial statements and are included elsewhere in this prospectus.

In the opinion of management, the unaudited consolidated financial statements reflect all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly in all material respects our financial position and results of operations for those periods. Historical results are not necessarily indicative of future expected results and the results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.

The following summary historical consolidated financial data should be read in conjunction with the information included under the headings “Selected Historical Consolidated Financial Data,” “Use of Proceeds,” “Capitalization” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited and unaudited consolidated financial statements and the related notes included elsewhere in this prospectus.

(In thousands, except for the number of shares outstanding and per share amounts)	Six months ended June 30,						Year ended December 31,
	2018			2017			2017			2016
Statement of operations
Total revenues(1)	$	306,094		$	216,373		$	434,411		$	203,319
Operating expenses(1):
Lease operating expenses		41,967			54,510			97,560			67,918
Workover, repair, and maintenance expenses		11,985			8,829			18,642			12,754
Transportation, gathering, and processing costs(2)		5,265			—			—			—
Depreciation, depletion, and amortization		96,473			88,911			170,372			104,584
General and administrative expenses		24,820			19,617			42,397			35,078
Accretion of asset retirement obligations		17,136			15,198			31,392			21,669
Total operating expenses	$	197,646		$	187,065		$	360,363		$	242,003
Operating income (loss)	$	108,448		$	29,308		$	74,048		$	(38,684	)
Other (expense) income:
Interest expense		(37,551	)		(29,835	)		(60,307	)		(31,545	)
(Loss) gain on derivatives, net		(37,649	)		41,141			5,020			(9,153	)
Interest income		2,473			2,111			4,370			3,916
Loss on extinguishment of long-term debt		(4,012	)		—			—			—
Loss on fair value of 11.00% Senior notes due 2023		(27,830	)		—			—			—
Total other (expense) income	$	(104,569	)	$	13,417		$	(50,917	)	$	(36,782	)
Income tax expense		416			11,504			14,095			—
Net income (loss)	$	3,463		$	31,221		$	9,036		$	(75,466	)
Net income (loss) attributable to non-controlling interest	$	338		$	4,767		$	2,581		$	(14,371	)
Net income (loss) attributable to EnVen Energy Corporation	$	3,125		$	26,454		$	6,455		$	(61,095	)
Series A preferred stock dividends		(15,794	)		(8,898	)		(21,590	)		(49	)

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(In thousands, except for the number of shares outstanding and per share amounts)	Six months ended June 30,						Year ended December 31,
	2018			2017			2017			2016
Net (loss) income attributable to EnVen Energy Corporation common stockholders	$	(12,669	)	$	17,556		$	(15,135	)	$	(61,144	)
Historical earnings (loss) per share data(3)
Net (loss) income per common share—basic	$	(0.79	)	$	1.06		$	(0.95	)	$	(4.13	)
Net (loss) income per common share—diluted	$	(0.79	)	$	1.01		$	(0.95	)	$	(4.13	)
Weighted average common shares outstanding—basic		16,131,324			15,865,947			15,912,950			14,795,005
Weighted average common shares outstanding—diluted		16,131,324			25,924,066			15,912,950			14,795,005
Adjusted earnings (loss) per share data(4)
Adjusted net (loss) income per common share—basic
Adjusted net (loss) income per common share—diluted
Adjusted weighted average common shares outstanding—basic
Adjusted weighted average common shares outstanding—diluted
Statement of cash flows data
Net cash provided by operating activities	$	168,799		$	85,371		$	191,482		$	26,954
Net cash used in investing activities	$	(82,805	)	$	(28,527	)	$	(84,759	)	$	(243,631	)
Net cash (used in) provided by financing activities	$	(16,413	)	$	(75,080	)	$	(99,406	)	$	242,633
Other financial data
Adjusted EBITDA(5)	$	212,190		$	151,993		$	300,125		$	92,707

(In thousands)	As of June 30, 2018		As of December 31, 2017
Balance sheet data
Cash and cash equivalents(6)		91,515		28,848
Accounts receivable		76,183		68,305
Other current assets		40,421		28,373
Total current assets	$	208,119	$	125,526
Property and equipment, net		682,486		691,490
Other non-current assets		133,149		126,025
Total assets	$	1,023,754	$	943,041
Current liabilities		166,348		140,375
Other non-current liabilities		627,983		552,281
Total liabilities	$	794,331	$	692,656
Total equity		229,423		250,385
Total liabilities and equity	$	1,023,754	$	943,041

(1) The total revenues and total operating expenses for the six months ended June 30, 2017 and the years ended December 31, 2017 and 2016 have not been adjusted to reflect the adoption of Accounting Standard Codification (“ASC”) 606, Revenue from Contracts with Customers (“ASC 606”) and include transportation, gathering, and processing costs as a reduction to total revenues and not as a component of operating expense.

(2) As a result of the adoption of ASC 606, we recorded $5.3 million of transportation, gathering, and processing costs for the six months ended June 30, 2018. Prior to the adoption of ASC 606 on January 1, 2018, certain transportation, processing, and gathering costs for our operated properties were presented net in oil, natural gas, and NGL revenues. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 2—Basis of Presentation and Summary of Significant Accounting Policies—Revenue—Adoption of ASC 606” for further discussion of the adoption of ASC 606.

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(3) Historical share and per share information does not give effect to the consummation of the Stock Split to be effected immediately prior to the completion of this offering.

(4) As adjusted amounts give effect to the consummation of the Stock Split to be effected immediately prior to the completion of this offering pursuant to which each share of common stock held by the holder of common share will be exchanged into              shares of common stock.

(5) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of net income (loss) to Adjusted EBITDA, see “—Non-GAAP Financial Measures” below.

(6) Does not include current portion of restricted cash of approximately $9.4 million and $6.8 million as of June 30, 2018 and December 31, 2017, respectively, reserved as cash collateral for certain bonding requirements and amounts held in escrow for plugging and abandonment obligations.

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure not calculated or presented in accordance with GAAP. Adjusted EBITDA is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) adjusted for DD&A, income tax expense, accretion of asset retirement obligations, non-cash stock-based compensation, interest expense, loss on extinguishment of long-term debt, loss on fair value of the 2023 Notes, loss (gain) on derivatives, net, cash (paid) received for derivative settlements, net, non-cash interest income and other expenses.

Management believes Adjusted EBITDA is useful because it allows management to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We adjust net income (loss) for the items listed above to arrive at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

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The following table presents a reconciliation of net income (loss) (the most comparable GAAP financial measure) to Adjusted EBITDA for each of the periods indicated.

	Six months ended June 30,						Year ended December 31,
(In thousands)	2018			2017			2017			2016
Net income (loss) reconciliation to Adjusted EBITDA:
Net income (loss)	$	3,463		$	31,221		$	9,036		$	(75,466	)
Depreciation, depletion, and amortization		96,473			88,911			170,372			104,584
Income tax expense(1)		416			11,504			14,095			—
Accretion of asset retirement obligations		17,136			15,198			31,392			21,669
Non-cash stock-based compensation(2)		3,668			2,491			6,066			3,057
Interest expense(3)		37,551			29,835			60,307			31,545
Loss on extinguishment of long-term debt(4)		4,012			—			—			—
Loss on fair value of 11.00% Senior notes due 2023(5)		27,830			—			—			—
Loss (gain) on derivatives, net		37,649			(41,141	)		(5,020	)		9,153
Cash (paid) received for derivative settlements, net		(13,771	)		16,010			18,047			1,601
Non-cash interest income(6)		(2,237	)		(2,036	)		(4,170	)		(3,793	)
Other expenses (7)		—			—			—			357
Adjusted EBITDA	$	212,190		$	151,993		$	300,125		$	92,707

(1) For the six months ended June 30, 2018, we recognized an effective tax rate of 10.7% compared to 26.9% for the six months ended June 30, 2017. For the year ended December 31, 2017, our effective tax rate was 60.9% compared to 0% in the year ended December 31, 2016.

(2) Includes non-cash compensation expenses associated with our restricted stock and restricted stock unit awards (together, “Restricted Stock”) and stock options.

(3) Includes interest expense and amortization of deferred financing costs and debt discount related to our Revolving Credit Facility and second lien term loan facility (the “Second Lien Term Loan”) and the amortization of our surety bond premiums. Additionally, the six months ended June 30, 2018 includes amortization and expensing of debt issuance costs associated with the 2023 Notes and modification related costs incurred as part of the 2018 Refinancing Transactions (as defined below) completed in February 2018. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations—Other Expenses—Interest Expense” below for further discussion.

(4) Related to the 2018 Refinancing Transaction completed in February 2018. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations—Other Expenses—Loss on Extinguishment of Long-term Debt” below for further discussion.

(5) Reflects changes in the fair value of the 2023 Notes accounted for using the fair value option. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 2—Basis of Presentation and Summary of Significant Accounting Policies—11.00% senior notes due 2023” for further discussion.

(6) Non-cash interest income relates to interest earned on notes receivable commitments from sellers of oil and natural gas properties, acquired by us, associated with our performance of assumed P&A obligations.

(7) Other expenses primarily includes certain ancillary costs incurred related to the issuance of common stock in 2015.

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SUMMARY HISTORICAL RESERVE AND PRODUCTION DATA

The following table sets forth summary data with respect to our estimated net oil, natural gas and NGL proved, probable and possible reserves as of July 31, 2018 and December 31, 2017.

The reserve estimates attributable to our assets presented in the tables below are based on fully-engineered reserve reports included elsewhere in this prospectus prepared by NSAI, using SEC pricing as of July 31, 2018 and December 31, 2017. The reserve reports were prepared in accordance with the rules and regulations of the SEC. Summaries of such reserve reports are included elsewhere in this prospectus.

The Standardized Measure and PV-10 values shown in the tables are not intended to represent the current market value of our estimated oil, natural gas and NGL reserves. You should refer to “Risk Factors,” “Business—Oil, Natural Gas and NGL Reserves—Proved Reserves,” “Business—Oil, Natural Gas and NGL Prices and Production,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited and unaudited consolidated financial statements and notes thereto appearing elsewhere in this prospectus in evaluating the material presented below.

	As of July 31, 2018(1)								As of December 31, 2017(1)
	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)		Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)
Proved developed reserves		32,512		47,876		1,426		41,917		31,735		37,234		1,042		38,983
Proved undeveloped reserves		11,658		13,386		356		14,245		11,667		15,386		385		14,616
Total proved reserves		44,170		61,262		1,782		56,162		43,402		52,620		1,427		53,599
Probable developed reserves		12,941		15,694		745		16,302		10,609		22,122		477		14,773
Probable undeveloped reserves		7,252		5,952		83		8,327		6,889		6,570		38		8,022
Total probable reserves		20,193		21,646		828		24,629		17,498		28,692		515		22,795
Possible developed reserves		19,748		29,502		1,058		25,723		11,543		7,912		587		13,449
Possible undeveloped reserves		7,207		12,277		186		9,439		6,362		13,113		169		8,717
Total possible reserves		26,955		41,779		1,244		35,162		17,905		21,025		756		22,166

(In thousands)	As of July 31, 2018(1)			As of December 31, 2017(1)
Proved reserve PV-10 value(2)(3)(4)		$	1,178,152		$	940,573
Standardized Measure		$	944,451		$	759,096
Probable reserve PV-10 value(2)(3)(4)		$	699,554		$	517,800
Possible reserve PV-10 value(2)(3)(4)		$	754,024		$	460,061

(1) Estimates of reserves as of July 31, 2018 and December 31, 2017 were prepared using SEC pricing as of July 31, 2018 and December 31, 2017, respectively. The unweighted arithmetic average first-day-of-the-month prices were $60.01 per Bbl and $51.34 per Bbl for oil and NGL volumes and $2.91 per MMBtu and $2.98 per MMBtu for natural gas volumes at July 31, 2018 and December 31, 2017, respectively, adjusted by field for quality, transportation fees and market differentials. Reserve estimates do not include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(2) PV-10 values represent the period-end present values of estimated future cash inflows from our proved, possible and probable reserves, less future development and production costs, discounted at 10% to reflect

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timing of future cash flows, using SEC pricing assumptions in effect at the end of the period. Our proved, possible and probable reserve PV-10 values are inclusive of cash inflows from the future net revenues related to third-party production handling agreements, discounted at 10%. The estimated future net revenues set forth above were determined by using reserve quantities of reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. Proved, possible and probable reserve PV-10 values are non-GAAP financial measures. See “—Non-GAAP Financial Measures—PV-10” below for a reconciliation of the proved reserve PV-10 value to the Standardized Measure, the most directly comparable GAAP measure.

(3) Inclusive of estimated future net revenues from third party production handling agreements, for which the PV-10 values vary by reserve category based on NSAI’s assumption for contract termination. Under existing agreements as of July 31, 2018, the proved reserve PV-10 value includes $20.7 million, which is expected to be received through December 31, 2020, the probable PV-10 value includes an additional $14.0 million, which is expected to be received through December 31, 2024, and the possible PV-10 value includes an additional $34.3 million, which is expected to be received through December 31, 2028. Under existing agreements as of December 31, 2017, the proved reserve PV-10 value includes $20.1 million, which is expected to be received through December 31, 2019, the probable PV-10 value includes an additional $13.0 million, which is expected to be received through December 31, 2025, and the possible PV-10 value includes an additional $28.5 million, which is expected to be received through December 31, 2032.

(4) The PV-10 value of our proved reserves is presented net of the estimated costs associated with our future expected P&A liabilities with a PV-10 of approximately $152.9 million. Our probable and possible reserve PV-10 values do not have any associated incremental future expected P&A liabilities; however, the estimated timing of when the P&A liabilities will be incurred could be delayed by the probable and possible incremental production volumes.

Non-GAAP Financial Measures

PV-10

Proved, possible and probable reserve PV-10 values are non-GAAP financial measures and represent the period-end present values of estimated future cash inflows from our proved, possible, and probable reserves, less future development and production costs, discounted at 10% to reflect the timing of future cash flows, using SEC pricing assumptions in effect at the end of the period. Our proved, possible and probable reserve PV-10 values are inclusive of cash inflows from the future net revenues related to third-party production handling agreements, discounted at 10%. The PV-10 value of our proved reserves is equal to Standardized Measure at the applicable date, the most directly comparable GAAP financial measure, before deducting future income taxes, discounted at 10%. GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves. Because PV-10 estimates of probable and possible reserves are more uncertain than PV-10 and standardized estimates of proved reserves, but have not been adjusted for risk due to that uncertainty, they may not be comparable with each other. Nonetheless, we believe that PV-10 estimates for reserve categories other than proved present useful information for investors about the future net cash flows of our reserves in the absence of a comparable GAAP measure such as Standardized Measure.

Generally, PV-10 is not equal to, or a substitute for, the GAAP financial measure of Standardized Measure. Our proved, possible and probable reserve PV-10 values and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves. However, we believe that the presentation of PV-10 is relevant and useful to investors because it presents the relative monetary significance of our properties regardless of tax structure. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our proved reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. In addition, investors should be cautioned that estimates of PV-10 for

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probable and possible reserves, as well as the underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. See “Risk Factors—Risks Related to Our Business—Oil, natural gas and NGL prices are volatile and declines in prices or an extended period of depressed prices will materially adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments” and “Risk Factors—Risks Related to Our Business—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

The following table provides a reconciliation of our proved reserve PV-10 value to the Standardized Measure at July 31, 2018 and December 31, 2017:

(In thousands)	As of July 31, 2018		As of December 31, 2017
Proved reserve PV-10 value	$	1,178,152	$	940,573
Present value of future income taxes discounted at 10%		213,002		161,359
Present value of future net revenues related to third-party production handling agreements discounted at 10%(1)		20,699		20,118
Standardized Measure	$	944,451	$	759,096

(1) As of July 31, 2018 and December 31, 2017, we expect to receive the estimated future net revenues from third-party production handling agreements through December 31, 2020 and December 31, 2019, respectively.

The following table sets forth information regarding our oil and natural gas production, realized oil, natural gas and NGL prices and production costs for the periods presented. For additional information, including with respect to price calculations, please read the information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Six months ended June 30,				Year ended December 31,
	2018		2017		2017		2016
Production volumes:
Oil (MBbls)		4,173		4,086		7,865		4,636
Natural gas (MMcf)		6,198		5,502		10,316		9,243
NGLs (MBbls)		127		145		301		279
Total (MBoe)		5,333		5,147		9,885		6,455
Average daily production (MBoe/d)		29.5		28.4		27.1		17.7
Average sales prices:
Oil, excluding effects of derivatives (per Bbl)	$	65.19	$	46.30	$	48.66	$	37.18
Oil, including effects of derivatives (per Bbl)(1)	$	61.86	$	50.06	$	50.67	$	37.68
Natural gas, excluding effects of derivatives (per Mcf)	$	3.64	$	2.92	$	2.93	$	2.12
Natural gas, including effects of derivatives (per Mcf)(1)	$	3.66	$	3.04	$	3.15	$	2.18
NGLs (per Bbl)	$	28.94	$	16.75	$	18.22	$	13.31
Average price per Boe, excluding effects of derivatives	$	55.93	$	40.35	$	42.33	$	30.32
Average price per Boe, including effects of derivatives	$	53.35	$	43.46	$	44.16	$	30.76
Average unit costs per Boe:
Lease operating expenses	$	7.87	$	10.59	$	9.87	$	10.52
Workover, repair, and maintenance expenses	$	2.25	$	1.72	$	1.89	$	1.98
Transportation, gathering, and processing costs(2)	$	0.99		—		—		—
General and administrative expenses	$	4.65	$	3.81	$	4.29	$	5.43

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(1) The effects of derivatives represent, as applicable to the periods presented: (i) current period derivative settlements; (ii) the exclusion of the impact of current period settlements for early-terminated derivatives originally designated to settle against future production period revenues; (iii) the exclusion of option premiums paid in current periods related to future production period revenues; (iv) the impact of the prior period settlements of early-terminated derivatives originally designated to settle against future production period revenues; and (v) the impact of option premiums paid in prior periods related to current period production revenues.

(2) As a result of the adoption of ASC 606, transportation, gathering, and processing costs were $5.3 million for the six months ended June 30, 2018. Prior to the adoption on January 1, 2018, certain transportation, gathering, and processing costs for our operated properties were presented net in oil, natural gas and NGL revenues. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 2—Basis of Presentation and Summary of Significant Accounting Policies—Revenue—Adoption of ASC 606” for further discussion of the adoption of ASC 606.

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RISK FACTORS

An investment in our Class A common stock involves risk. You should carefully consider the following risks and all of the other information set forth in this prospectus, including “Selected Historical Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes, before deciding to invest in shares of our Class A common stock. If any of the following risks actually occurs, our business, financial condition or results of operations would likely suffer. However, the selected risks described below are not the only risks facing us. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial may also materially and adversely affect our business, financial condition or results of operations. In any of such cases, the trading price of our Class A common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business

Oil, natural gas and NGL prices are volatile and declines in prices or an extended period of depressed prices will materially adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

• domestic, regional and worldwide economic conditions impacting the global supply and demand for oil, natural gas and NGLs;

• the price and quantity of foreign imports;

• political and economic conditions in or affecting other producing countries, including the Middle East, Africa, South America and Russia;

• the ability of members of the Organization of the Petroleum Exporting Countries (“OPEC”) to agree to and maintain oil price and production controls;

• the level of oil and natural gas global exploration and production;

• the level of global oil, natural gas and NGL inventories;

• prevailing prices on local price indexes in the areas in which we operate;

• the proximity, capacity, cost, and availability of gathering and transportation facilities;

• localized and global supply and demand fundamentals and transportation availability;

• the cost of exploring for, developing, producing and transporting reserves;

• weather conditions and natural disasters;

• technological advances affecting energy consumption;

• risks associated with operating, drilling and working over rigs;

• the price and availability of alternative fuels;

• the price and availability of competitors’ supplies of oil, natural gas and NGL;

• expectations about future commodity prices;

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• potential changes in U.S. laws restricting oil exports; and

• domestic, local and foreign governmental regulation and taxes.

Since the second half of 2014, oil prices have declined significantly. After averaging approximately $90.00 per Bbl in 2014, NYMEX WTI crude oil prices declined to an average of approximately $43.00 per Bbl in 2016 and an average of approximately $50.00 per Bbl in 2017. NYMEX WTI crude oil prices reached a high above $74.00 per Bbl during the six months ended June 30, 2018. The International Energy Agency (“IEA”) forecasts a steady or slightly increasing U.S. production growth and a slowdown in global demand growth for the remainder of 2018. This environment could cause the prices for oil to remain at current levels or to fall to lower levels, though oil prices have increased somewhat from the lows of the first quarter of 2016. On December 31, 2014, the NYMEX HH price for natural gas was $3.14 per MMBtu. The NYMEX HH price for natural gas declined to an average approximately between $2.50 per MMBtu to $2.60 per MMBtu during 2015 and 2016 and an average of approximately $3.00 per MMBtu in 2017. The NYMEX HH price for natural gas reached a high above $3.60 per MMBtu during the six months ended June 30, 2018. The reduction in prices has been caused by many factors, including increases in natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand or an expectation of increasing demand. The expected increase in natural gas production, based on reports from the IEA, could cause the prices for natural gas to remain at current levels or fall to lower levels.

Substantially all of our production is sold to purchasers at market-based prices. Lower oil, natural gas and NGL prices will reduce our cash flows, borrowing ability and the present value of our reserves. If oil, natural gas and NGL prices materially deteriorate, we anticipate that the revised borrowing base under our Revolving Credit Facility may be reduced as the borrowing base depends, in part, upon projected revenues from, and asset values of, the oil and natural gas properties securing the facility. Any such reduction to the borrowing base under our Revolving Credit Facility could impact our capital expenditures. For a discussion of our capital expenditure requirements, see “—Our exploitation, development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow reserves.”

In addition, lower oil, natural gas and NGL prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically and may affect our proved reserves. Our estimated proved reserves as of July 31, 2018 and December 31, 2017 and related PV-10 and Standardized Measure of our proved reserves were calculated under SEC rules using 12-month trailing average benchmark prices based on WTI of $60.01 per Bbl and $51.34 per Bbl, respectively, and HH of $2.91 per MMBtu and $2.98 per MMBtu, respectively. On July 31, 2018 and December 31, 2017, the NYMEX WTI price for crude oil was $68.76 per Bbl and $60.42 per Bbl, respectively, and the NYMEX HH price for natural gas was $2.78 per MMBtu and $2.95 per MMBtu, respectively. Using lower prices in estimating our proved reserves would likely result in a reduction in proved reserve volumes due to economic limits, which would reduce the PV-10 and Standardized Measure of our proved reserves and could materially affect our business, financial condition and results of operations.

If oil, natural gas and NGL prices are depressed or decrease, we may be required to record write-downs of the carrying value of our oil and natural gas properties.

We follow the full cost method of accounting for our oil and natural gas properties. Under such method, the net book value of properties less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling is then estimated after tax future net revenues from proved oil and natural gas properties, discounted at 10% per year. Discounted future net revenues are estimated using oil, natural gas, and NGL prices based on the average price during the preceding 12-month period determined as an unweighted, arithmetic average of the first-day-of-the-month price for each month within such period, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense of impairments of oil and natural gas properties.

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For the six months ended June 30, 2018 and 2017 and the years ended December 31, 2017 and 2016, we did not recognize a write-down of the carrying value of our oil and natural gas properties. Since the nature of our business is tied to the commodity price environment, reductions in oil, natural gas, and NGL prices could result in full cost ceiling impairments in future periods. Sustained low prices for oil and natural gas will negatively impact the value of our estimated proved reserves and reduce the amounts of cash we would otherwise have available to pay expenses and service any indebtedness that we may incur. Under the full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. In addition, some of our undeveloped locations may no longer be economically viable.

Our derivative activities could result in financial losses or could reduce our earnings.

We have entered into derivative instrument contracts for a significant portion of our estimated production from our proved producing developed oil properties. Our Revolving Credit Facility required us to hedge a significant portion of our estimated production from our proved producing developed properties through 2019. We currently do not have any hedges in place for the first quarter of 2020 and beyond. Our earnings may fluctuate significantly as a result of changes in the fair value of such derivative instruments. Such derivative instruments are subject to the risks and uncertainties described in this prospectus under “Special Note Regarding Forward-Looking Statements.” The portion of our estimated production from our proved producing developed oil properties that are unhedged exposes us to commodity price risk. For a discussion of minimum hedge requirements under our credit facility, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Our earnings may fluctuate significantly as a result of changes in the fair values of our derivative instruments. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

• production is less than the volume covered by the derivative instruments;

• the counterparty to the derivative instrument defaults on its contractual obligations;

• there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

• there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.

As of June 30, 2018, the fair value of our commodity derivative contracts was a net liability of $41.8 million. During the six months ended June 30, 2018, we recognized a loss of $37.6 million on our derivatives primarily due to an increase in the future commodity price outlook during the six months ended June 30, 2018. Any default by the counterparties to our derivative contracts when they become due could have a material adverse effect on our business, financial condition and results of operations. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.

We may not be able to secure new hedging contracts for our future estimated production from our proved producing developed oil and natural gas properties after the termination of our current hedging contracts. Any future unhedged estimated production from our proved producing developed oil and natural gas properties may cause our earnings to decline significantly as a result of any decreases in the prices for oil and natural gas. Further, under the terms of our Revolving Credit Facility, the percentage of our total estimated production from

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our proved producing developed oil and natural gas properties with respect to which we are allowed to enter into derivative contracts is limited, particularly during hurricane season, and we therefore retain the risk of a price decrease for our remaining estimated production from our proved producing developed oil and natural gas properties.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses or properties, and any inability to do so may hinder our ability to grow and could materially adversely affect our results of operations, financial position and cash flows.

We intend to grow our business through focused and strategic acquisitions designed to reduce the risk of underperformance on the acquired properties. Our acquisition strategy may fail to identify attractive acquisition opportunities that meet our target criteria for potential production improvements and field cost reductions. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.

In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.

The successful acquisition of producing properties requires an assessment of several factors, including:

• recoverable reserves;

• future oil, natural gas and NGL prices and their applicable differentials;

• operating costs; and

• potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, financial condition and results of operations.

There can be no assurance that we will be able to fully realize the anticipated benefits of any future acquisitions. Achieving the benefits of any future acquisitions depends in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as our ability to realize the anticipated growth opportunities and synergies from combining the acquired assets and operations with our current operations. Additionally, the integration of acquired assets or businesses requires the dedication of substantial management effort, time and resources which may divert management’s focus and resources from other strategic opportunities and from operational matters during this process. The integration

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process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect our ability to achieve the anticipated benefits of the acquisitions. Furthermore, consummated acquisitions may in fact result in an increase in G&A expenses, capital expenditures and operating expenses and a corresponding decrease in cash flows.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and can adversely affect our business, financial condition and results of operations. While we typically review title searches and sometimes obtain title opinions prior to acquiring leases or commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Our exploitation, development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow reserves.

The oil and natural gas industry is capital intensive. We make, and expect to continue to make, substantial capital expenditures for the exploitation, development and exploration of oil and natural gas reserves, and our capital expenditures have historically exceeded cash generated by our operations in a given period. We expect to fund 2018 capital expenditures with cash on hand and cash generated by operations, based on current commodity prices. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices; actual drilling results; the availability of services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our near-term capital expenditures primarily through cash flow from operations; however, our financing needs may require us to draw on our Revolving Credit Facility or alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.

Our cash flow from operations and access to capital are subject to a number of variables, including:

• our proved reserves;

• the level of hydrocarbons we are able to produce from existing wells;

• the prices at which our production is sold;

• the level of our operating expenses;

• our ability to acquire, locate and produce new reserves; and

• our ability to borrow under our Revolving Credit Facility.

If our revenues or the borrowing base under our Revolving Credit Facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our Revolving Credit Facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations. For a discussion on the risks of incurring substantial indebtedness, see “—Our indebtedness could adversely affect our ability to raise additional capital to fund our operations and limit our ability to react to changes in the economy or our industry.”

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Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could result in a total loss of investment or otherwise materially adversely affect our business, financial condition or results of operations.

Our future business, financial condition and results of operations will depend on the success of our exploitation, development and exploration activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable hydrocarbons production, including dry holes, that we will not recover all or any portion of our investment in such wells or that various characteristics of such wells will cause us to plug or abandon such wells prior to their producing in commercially viable quantities.

Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

• delays or restrictions imposed by or resulting from compliance with regulatory requirements including limitations resulting from wastewater disposal and discharge of greenhouse gases;

• pressure or irregularities in geological formations;

• loss of control or equipment malfunctions;

• shortages of or delays in obtaining equipment and qualified personnel;

• equipment failures, accidents or other unexpected operational events;

• lack of available gathering facilities or delays in construction of gathering facilities;

• lack of available capacity on interconnecting transmission pipelines;

• adverse weather conditions, including hurricanes and tropical storms;

• issues related to compliance with environmental and other governmental regulations;

• environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, releases of well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

• declines in oil, natural gas, and NGL prices;

• limited availability of financing at acceptable terms;

• title issues; and

• limitations in the market for oil and natural gas.

These risks may cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties, any of which could materially adversely affect our business, financial condition and results of operations.

Furthermore, the marketability of expected oil and natural gas production from our discoveries and prospects will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of prices (such as significant declines in oil prices), proximity, capacity and availability of drilling

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rigs and related equipment, qualified personnel and support vessels, processing facilities, transportation vehicles and pipelines, equipment availability, access to markets and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, domestic supply requirements, importing and exporting of oil and natural gas, the ability to flare or vent natural gas, environmental protection and climate change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, including those in our third party reserve engineer reserve estimates presented herein, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil, natural gas, and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates, including those included in our July 31, 2018 and December 31, 2017 reserve reports prepared by NSAI. Any significant variance from the above assumptions could materially affect the estimated quantities and present value of our reserves. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than we estimate and may be rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates would have a material adverse effect on our business, financial condition and results of operations.

The net production estimates and forecasts for our capital programs may differ materially from the actual amounts.

The production estimates with respect to our capital programs described in this prospectus are based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines. These estimates of reserves and production are based on estimates of our engineers without review by an independent reserve engineering firm. We cannot assure you that these estimates of production are accurate and the actual production related to our capital programs may differ materially from the amounts indicated in this prospectus.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves.

The present value of future net cash flows from our proved reserves is referred to as the Standardized Measure, which is a reporting convention that provides a common basis for comparing oil and natural gas

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companies subject to the rules and regulations of the SEC. Standardized Measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil, natural gas, and NGL production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the Standardized Measure of our estimated reserves included in this prospectus should not be construed as accurate estimates of the current fair value of our proved reserves.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

Relatively short production periods or reserve lives for some U.S. Gulf of Mexico properties subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil, natural gas and NGL prices.

High production rates can result in the recovery of a relatively higher percentage of booked reserves from properties in the U.S. Gulf of Mexico during the initial few years when compared to onshore regions in the U.S. Due to high initial production rates, production of booked reserves from reservoirs in the U.S. Gulf of Mexico can decline more rapidly than from other producing reservoirs. Nearly all of our existing operations are in the U.S. Gulf of Mexico or directly support our U.S. Gulf of Mexico operations. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and natural gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during what can be relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay outstanding indebtedness may limit our ability to slow or shut in production from producing wells during periods of low prices for oil, natural gas, and NGLs.

Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will materially adversely affect our business, financial condition and results of operations. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercially viable quantities. We cannot assure you that the analogies we draw from available data from other wells or more fully explored or producing prospects will be applicable to our drilling prospects. In addition, the wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices for oil, natural gas and NGLs, expected costs associated with producing oil, natural gas and NGLs and our ability to add reserves at an acceptable cost. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors. See “—Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could result in a total loss of investment or otherwise materially adversely affect our business, financial condition or results of operations.”

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Our identified potential drilling locations, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our identified potential drilling locations, including those without associated proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory approvals, commodity prices, lease expirations, our ability to secure rights to drill at deeper formations, costs and drilling results.

Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional analysis of data. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas reserves in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technology and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas reserves will be present or, if present, whether oil or natural gas reserves will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill dry holes in our current and future drilling locations, our drilling success rate will decline and may materially harm our business. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations.

Further, initial production rates reported by us or other operators in the areas in which we operate may not be indicative of future or long-term production rates. Of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas reserves from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business, financial condition and results of operations.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

As of July 31, 2018, approximately 25% of our total estimated proved reserves were classified as proved undeveloped and were estimated to require approximately $272.0 million of future development costs. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves. Further, we may be required to write down our proved undeveloped reserves if we do not drill those wells within five years after their respective dates of booking. Our probable and possible undeveloped reserves primarily represent incremental production volumes in excess of volumes considered proved based on the rules and regulations of the SEC. Due to the nature of our probable and possible undeveloped reserves, there are not significant future development costs associated with our probable or possible undeveloped reserves. Although we intend to fund the future development costs associated with our proved, probable and possible undeveloped reserves with cash on hand and cash generated by operations, based on current commodity prices, there is no certainty such cash on hand and cash generated by operations will be sufficient to fund the required future development costs. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. Furthermore, the actual costs to develop our proved, probable and possible undeveloped reserves may be materially greater than what we currently estimate. intend to fund the future development costs

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associated with our proved, probable and possible undeveloped reserves with cash on hand and cash generated by operations, based on current commodity prices, there is no certainty such cash on hand and cash generated by operations will be sufficient to fund the required future development costs. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. Furthermore, the actual costs to develop our proved, probable and possible undeveloped reserves may be materially more than what we currently estimate.

Our indebtedness could adversely affect our ability to raise additional capital to fund our operations and limit our ability to react to changes in the economy or our industry.

As of June 30, 2018, we had $325.0 million of aggregate principal amount of 2023 Notes outstanding, no outstanding borrowings under our Revolving Credit Facility and availability of $271.4 million (after giving effect to $3.6 million of outstanding letters of credit), subject to the borrowing base. Because our borrowing capacity under the Revolving Credit Facility depends, in part, upon projected revenues from, and asset values of, the oil and natural gas properties securing the facility, which fluctuates from time to time, the availability under the Revolving Credit Facility also fluctuates from time to time. See “Management’s Discussion and Analysis of Financial Condition—Liquidity and Capital Resources—Other Significant Sources of Liquidity—Revolving Credit Facility.”

Subject to the limits contained in the credit agreement governing the Revolving Credit Facility and the indenture that governs the 2023 Notes, we may be able to incur substantial additional debt from time to time to finance working capital, capital expenditures, investments or acquisitions or for other purposes. If we do so, the risks related to our level of debt could intensify.

Our consolidated indebtedness could have important consequences, including but not limited to the following:

• making it more difficult for us to satisfy our obligations with respect to our existing indebtedness;

• it may limit our flexibility in planning for, or reacting to, changes in our operations or business;

• it may make us more vulnerable to downturns in our business or in the economy;

• a significant portion of our cash flows from operations will be dedicated to the repayment of our indebtedness and will not be available for working capital, capital expenditures, acquisitions and other general corporate purposes;

• it may restrict us from making strategic acquisitions, introducing new technologies or exploiting business opportunities;

• it may adversely affect terms under which suppliers provide material and services to us; and

• it may limit our ability to borrow additional funds or dispose of assets.

In addition, the indenture that governs the 2023 Notes and the credit agreement governing the Revolving Credit Facility contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interest.

There would be a material adverse effect on our business, financial condition and results of operations if we were unable to service our indebtedness or obtain additional financing, as needed.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including the Revolving Credit Facility and the 2023 Notes, depends on our financial condition and operating performance,

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which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The credit agreement governing the Revolving Credit Facility and the indenture governing the 2023 Notes restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due.

If we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the Revolving Credit Facility and the 2023 Notes, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable. Under these circumstances, our lenders and creditors could compel us to apply all of our available cash to repay our borrowings. In addition, the lenders under the Revolving Credit Facility and the holders of the 2023 Notes could seek to foreclose on our assets that constitute their collateral. If the amounts outstanding under our indebtedness were to be accelerated, or were the subject of foreclosure actions, our assets may not be sufficient to repay in full the money owed to the lenders, and such payment acceleration would have a material adverse effect on our liquidity, business and financial condition.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

The credit agreement governing the Revolving Credit Facility and the indenture governing the 2023 Notes each contain, a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:

• incur additional indebtedness and guarantee indebtedness;

• pay dividends or make other distributions on, or redeem or repurchase, capital stock and make other restricted payments;

• prepay, redeem or repurchase certain debt;

• issue certain preferred stock or similar equity securities;

• make loans or investments;

• consummate certain asset sales;

• engage in transactions with affiliates;

• grant or assume liens;

• alter the businesses we conduct;

• enter into agreements restricting our subsidiaries’ ability to pay dividends; and

• consolidate, merge or transfer all or substantially all of our assets.

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In addition, the credit agreement governing the Revolving Credit Facility and the indenture governing the 2023 Notes require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of such limitations.

A default, if not waived, could result in acceleration of the indebtedness outstanding under the Revolving Credit Facility and the 2023 Notes and in a default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements. The accelerated indebtedness would become immediately due and payable and could result in the acceleration of any other debt to which a cross-acceleration or cross-default provision applies. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. Furthermore, if we were unable to repay the amounts due and payable under the Revolving Credit Facility or the 2023 Notes, those lenders or noteholders could proceed against the collateral granted to them to secure such indebtedness.

We are currently dependent on Shell for a substantial majority of our revenues. Therefore, we are indirectly subject to the business risks of Shell. We have no control over Shell’s business decisions and operations, and Shell is under no obligation to adopt a business strategy that favors us.

We typically sell our production to a relatively small number of customers, as is customary in the exploration, development and production business. Historically, we have sold a large portion of our oil production to Shell. For the six months ended June 30, 2018 and the years ended December 31, 2017 and 2016, sales to Shell accounted for approximately 87%, approximately 85% and approximately 69% of our total revenue, respectively. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 14—Related Party Transactions” and “Notes to Consolidated Financial Statements—Note 17—Related Party Transactions” for further discussion of our relationship with Shell as of and for the six months ended June 30, 2018 and the years ended December 31, 2017 and 2016, respectively.

We expect to derive a substantial majority of our revenues from Shell for the foreseeable future. Therefore, any event, whether in our area of operations or otherwise, that adversely affects Shell’s financial condition, leverage, results of operations or cash flows may materially and adversely affect our revenues. Accordingly, we are indirectly subject to the business risks of Shell, some of which are the following:

• the volatility of oil and natural gas prices, which could have a negative effect on its ability to purchase and sell oil and natural gas or its ability to finance its operations;

• the availability of capital on an economic basis to fund its trading activities;

• its operating risks, including potential environmental liabilities;

• transportation capacity constraints and interruptions;

• adverse effects of governmental and environmental regulation; and

• losses from pending or future litigation.

Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

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Our use of seismic data is subject to the terms of various non-exclusive license agreements and changes to our corporate structure and ownership may affect our rights under those agreements.

Our 3-D seismic license agreements are non-exclusive, industry-standard agreements. Accordingly, the licensor of such seismic data has the right to license the same data to our competitors, which could adversely affect our acquisition strategy and the execution of our business plan. We are also not authorized to assign any of our rights under our license agreements, including in a transaction with a potential joint venture partner or acquirer, without complying with the terms of the license agreements and a payment to the licensor (by us or by the acquirer in the event of a change of control transaction or our partner in a joint venture transaction).

Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, collisions with other vessels, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, as well as natural disasters such as currents and hurricanes. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and repairs to resume operations.

Our operations in the U.S. Gulf of Mexico and Gulf Coast region are particularly susceptible to interruption and damage from hurricanes. Any of these operating hazards could cause personal injuries, fatalities, oil spills, discharge of hazardous substances into the air and water or environmental damage, lost production and revenue, remediation and clean-up costs and liability for damages, all of which could adversely affect our business, financial condition and results of operations and may not be fully covered by our insurance.

We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, each party typically assumes all responsibility for control and removal of pollution or contamination which arises out of, is related to, incident to, connected with or results from its performance of its obligations under such agreements, regardless of the source of such pollution. Nevertheless, vendors often seek to alter this basic allocation of pollution risk so that (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which is directly associated with such vendors’ equipment while in their control or for pollution or contamination that occurs above the surface of the water and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, natural gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally employ a knock-for-knock indemnity for equipment and property, but in some instances, when appropriate for the applicable vendor, we agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the wellbore and for loss of rental equipment while in our care, custody and control. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially adversely affect our business, financial condition and results of operations.

In accordance with what we believe to be customary industry practice, we maintain insurance against most, but not all, of our business risks. Our insurance may not be adequate to cover all losses or liabilities we may suffer. We do not insure against business interruption. Also, in the future, insurance may no longer be available

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to us or, if it is, its availability may be at costs that do not justify its purchase. Available forms of business interruption insurance that insure against potential lost or delayed production and related cost flow are cost prohibitive for us. The occurrence of a significant uninsured claim, a claim in excess of insurance coverage limits or a claim at a time when we are not able to or choose not to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might adversely impact our financial condition. We may also be liable for environmental damages caused by previous owners of properties purchased or acquired by us, for which liabilities may not be covered by insurance.

We maintain insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, the insurance coverage may not be adequate to cover claims that may arise and we may not be able to maintain adequate insurance at rates we consider reasonable. We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business—Operational Hazards and Insurance.”

Our offshore operations involve special risks that could affect operations adversely.

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or acquisitions, or result in loss of equipment and properties. In particular, we do not intend to put in place business interruption insurance due to its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena.

In addition, an oil spill on or related to our properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which could be material to our results of operations and financial position.

Our operations may be materially adversely affected by tropical storms and hurricanes.

Tropical storms, hurricanes and the threat of tropical storms and hurricanes often result in the shutdown of operations in the U.S. Gulf of Mexico as well as operations within the path and the projected path of the tropical storms or hurricanes. In addition, climate change could result in an increase in the frequency and severity of tropical storms, hurricanes or other extreme weather events. Recent weather events, such as Hurricane Harvey in 2017, caused significant disruption to the operations of offshore and coastal facilities in the U.S. Gulf of Mexico region. In the future, during a shutdown period, we may be unable to access wellsites and our services may be shut down. Additionally, tropical storms or hurricanes may cause evacuation of personnel and damage to our platforms and other equipment, which may result in suspension of our operations. The shutdowns, related evacuations and damage can create unpredictability in activity and utilization rates, as well as delays and cost overruns, which could have a material adverse effect on our business, financial condition and results of operations.

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The geographic concentration of our properties in the U.S. Gulf of Mexico subjects us to an increased risk of loss of revenues or curtailment of production from factors affecting the U.S. Gulf of Mexico specifically.

The geographic concentration of our properties in the deepwater of the U.S. Gulf of Mexico means that some or all of our properties could be affected by the same event should the U.S. Gulf of Mexico experience:

• severe weather, including hurricanes and tropical storms;

• delays or decreases in production, the availability of equipment, facilities or services;

• changes in the status of pipelines that we depend on for transportation of our production to marketplace;

• delays or decreases in the availability of capacity to transport, gather or process production; or

• changes in the regulatory environment.

In addition, as of July 31, 2018, our top five fields constituted approximately 79% of our proved reserves, which may exacerbate the risks set forth above. Because a substantial portion of our properties could experience the same adverse condition at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.

Many of our larger competitors not only explore for and produce oil, natural gas, and NGLs, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. There is substantial competition for investment capital in the oil and natural gas industry and many of our competitors have access to capital at a lower cost than that available to us. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical or personnel resources permit. These larger companies may have a greater ability to continue exploration activities during periods of low oil, natural gas, and NGL prices and to absorb the burden of existing, and any changes to, federal, state, local and other laws and regulations more easily than we can. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse effect on our business, financial condition and results of operations. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, raising additional capital and attracting and retaining quality personnel, which could have a material adverse effect on our business, financial condition and results of operations.

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The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable or there are changes in or challenges to our rates and other terms and conditions of service, our operations could be interrupted and our revenues reduced.

The marketability of our oil, natural gas, and NGL production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our share of oil, natural gas, and NGL production from our properties is sold under a series of arm’s length contracts awarded on a competitive bid basis or entered into following negotiations. Oil is sold directly to companies with refineries in the Gulf Coast regions of Texas and Louisiana at prices based on widely-used industry benchmarks. Gas is processed in one of nine large onshore gas plants, where we are paid our contractual share of revenues from the sale of natural gas. We sell our residue gas to a purchaser who delivers to various industrial and energy markets as well as intrastate and interstate pipeline systems.

We use a series of pipelines, most of which are not ours, to transport our oil, natural gas, and NGL production from our offshore platforms to shore. These movements are made under a combination of transportation contracts and tariffs, in some instances, subject to regulation by the Federal Energy Regulatory Commission (“FERC”). Natural disasters or other operational situations beyond our control could result in increased transportation costs to us or require us to find transportation alternatives. Such circumstances may also cause us to involuntarily curtail our production.

There are a limited number of alternative methods of transportation for our offshore production. Since a substantial portion of our oil, natural gas, and NGL production is transported by pipelines owned by third parties, the inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in us having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our oil, natural gas, and NGL production which could have a material adverse effect on our results of operations and cash flows.

The rates charged on certain of these pipeline systems are regulated by the FERC or state regulatory agencies, or both. These regulatory agencies also regulate other terms and conditions of the services these pipeline systems provide, including the types of services offered. If one of these regulatory agencies, on its own initiative or in response to a request by the pipeline owner, pipeline operator or a third party, were to alter the tariff rates or make any other material changes to the types or terms and conditions of services available to us, the cost of transporting our oil, natural gas, and NGLs could increase. Furthermore, the regulatory agencies that regulate pipeline systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates we charge or pay for pipeline services, or otherwise materially adversely affect our business, financial condition, results of operations and cash flows.

We are, in part, dependent on third-party operators who influence our productivity.

With respect to oil and natural gas projects that we do not operate, we have limited influence over operations, including limited control over the maintenance of safety and environmental standards. The operators of those properties may, depending on the terms of the applicable joint operating agreement:

• refuse to initiate exploration or development projects;

• initiate exploration or development projects on a slower or faster schedule than we would prefer;

• delay the pace of exploratory drilling or development; and/or

• drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.

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The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could materially affect our ability to execute our exploitation and development plans within our budget and on a timely basis.

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, natural gas, and NGL prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire. Equipment shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition and results of operations.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition and results of operations could be materially adversely affected.

Our operations are subject to complex laws and regulations, including evolving environmental and occupational health and safety laws and regulations. These laws and regulations could adversely affect the manner or feasibility of conducting our operations. Additionally, we may incur significant delays, costs and liabilities that could have a material adverse effect on our business, financial condition and results of operations.

Our oil and natural gas exploitation, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages, as well as injunctions limiting or prohibiting our activities. These regulations could also change to our detriment. Our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety laws and regulations applicable to our exploitation, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to the generation, transportation and disposal of hazardous substances, waste disposal, air emissions, water discharges, remediation, restoration and reclamation of environmental contamination, including oil spill cleanup and well plugging and abandonment requirements, protection of endangered and other protected species, and related matters. We are also subject to extensive regulation of worker health and safety. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal

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penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and worker health and safety impacts of our operations. We have been named from time to time as a defendant in litigation related to such matters. Also, new laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities, significantly increase our operating or compliance costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business. If we are not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be materially and adversely affected. See “Business—Regulation of the Oil and Natural Gas Industry—Environmental Regulations and Worker Health and Safety” for a further description of laws and regulations that affect us.

Environmental liabilities could adversely affect our business, financial condition and results of operations.

Environmental liabilities, including those related to our recent environmental investigation, could adversely affect our business, financial condition and results of operations. The oil and natural gas business is subject to environmental hazards, such as oil spills, gas leaks, ruptures, fires and discharges of petroleum products and hazardous and other substances and historical disposal activities. These environmental hazards could expose us to material liabilities, such as for property damages, personal injuries, criminal fines and penalties or environmental remediation measures, including costs of investigating and remediating contaminated properties. We also may be liable for environmental damages caused by the previous owners or operators of properties we have purchased or are currently operating. A variety of stringent federal, state and local laws and regulations govern the environmental aspects of our business and impose strict requirements for, among other things:

• well drilling or workover, operation and abandonment;

• waste management;

• financial assurance; and

• controlling air emissions, preventing water contamination and unauthorized waste discharges.

Recent proposed and final regulations include the following:

• Ground-Level Ozone Standards. In October 2015, the U.S. Environmental Protection Agency (“EPA”) issued a final rule under the Clean Air Act (“CAA”) lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 to 70 parts per billion. The EPA made the majority of area designations pursuant to this rule on November 16, 2017 and June 4, 2018 and finalized designations for the remaining regions of the country on July 25, 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and increased expenditures for pollution control equipment, the costs of which could be significant.

• Protected and Endangered Species. We conduct operations on leases in areas where certain species are known to exist that are currently protected or could become protected under state and federal laws. The presence of protected species, marine protection areas and other similar areas where we operate could cause increased costs arising from species or habitat protection measures, or could result in limitations or prohibitions on our exploration and production activities.

Any noncompliance with these laws and regulations could subject us to administrative, civil or criminal penalties or other liabilities. As discussed under “Business—Environmental Compliance Matter,” in September 2018 we made self-disclosures to the EPA regarding an improperly filtered water sample, an inaccurate report

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and improper disposal of water clarifier liquids, and formally reported a fire incident to the Bureau of Safety and Environmental Enforcement (“BSEE”), in each case in connection with the Cognac platform. The EPA is currently conducting an investigation based on our self-disclosures. We are uncertain at this time whether the EPA will pursue administrative, civil, or criminal penalties or injunctive relief, if any, against EnVen, nor are we certain what actions, if any, BSEE may pursue. Resolution of any criminal claims pursued against EnVen could result in substantial monetary fines and penalties, probation, a monitor program, injunctive action or suspension and debarment from operational activities. We are not able at this time to definitively determine EnVen’s potential financial or other exposure related to these matters, nor the timing to fully resolve these matters. However, any financial or other penalties or actions imposed on EnVen in connection with these matters may have a material adverse effect on our business, results of operations or financial performance.

Additionally, our compliance with environmental, health and safety and other laws may, from time to time, result in increased costs to our operations or decreased or delayed production, and may affect our costs of acquisitions. In addition, existing, modified or new environmental laws may, in the future, cause a decrease or delay in our production or cause an increase in our costs of production, development or exploration. Pollution and similar environmental risks generally are not fully insurable, so we may have to bear these additional costs in full.

We have plugging and abandonment obligations related to our current and former oil and natural gas operations and are required to provide bonds or other forms of financial assurance in connection with those operations. Changes in these requirements could have a material adverse effect on us.

We are subject to state and federal laws that impose financial assurance requirements in connection with our oil and natural gas operations, such as bonding and insurance requirements in order to drill, operate, and plug and abandon wells. Procuring and placing financial assurance, such as bonds, letters of credit, or sinking escrow or trust accounts, may be costly and, depending on our financial condition and market conditions, may be difficult or impossible to obtain. Failure to provide the required financial assurance could result in the suspension of the affected operations and/or production.

The BOEM and the BSEE have regulations applicable to lessees in federal waters that require lessees to have substantial U.S. assets and net worth or post bonds or other acceptable financial assurance that the regulatory obligations will be met. Financial responsibility requirements are also required under the Oil Pollution Act (“OPA”) to cover containment and cleanup costs resulting from an oil spill.

In July 2016, BOEM issued a new Notice to Lessees and Operators (“NTL”), which has not been implemented and is currently under review by BOEM. The NTL augments requirements for the posting of financial assurance by offshore lessees and discontinues the policy of supplemental bonding waivers. During the review period, BOEM has primarily focused on requiring incremental financial assurance or bonding for sole liability properties (properties with no predecessor or co-lessees), with which EnVen is currently in compliance. However, changes to the NTL, or any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements regarding financial assurances or otherwise adversely affecting our offshore activities could result in increased costs and consequently have a material adverse effect on our business, financial condition and results of operations.

As of June 30, 2018, our asset retirement obligations totaled $162.9 million, net of restricted cash and restricted cash equivalents for abandonment obligations and sellers’ notes payable and escrowed cash as per our estimates.

Climate change legislation or regulations restricting greenhouse gas emissions may increase our costs, adversely affect our operations and impact the demand for the oil and natural gas that we produce.

Since 2009, the EPA has been monitoring and regulating greenhouse gas (“GHG”) emissions from certain sources in the oil and natural gas sector due to their association with climate change. Our facilities are subject to

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the EPA’s GHG reporting rules that cover offshore (as well as onshore) oil and natural gas production, processing, transmission, storage and distribution facilities. Under these rules, reporting of GHG emissions from such facilities, which includes most of our facilities, is required on an annual basis. The continued compliance with these rules could result in increased compliance costs for our operations.

From time to time, the U.S. Congress has considered legislation to regulate GHG emissions, and many states have already taken legal measures to reduce emissions of GHG. In August 2015, the EPA finalized the Clean Power Plan (“CPP”), which set forth binding guidelines for GHG emissions from existing power plants as well as New Source Performance Standards regulating GHG emissions from new, modified and reconstructed power plants (“Power Plant NSPS”). On March 28, 2017, President Trump signed an executive order (the “March 2017 Executive Order”) directing the EPA to initiate a rulemaking to suspend, revise or rescind both the CPP and the Power Plant NSPS (as well as other regulations relating to the energy industry) as necessary to ensure consistency with the goals of energy independence, economic growth and cost-effective environmental regulation. On April 4, 2017, the EPA announced in the Federal Register that it is initiating its review of the Power Plant NSPS and CPP, and on August 21, 2018, the EPA proposed to replace the CPP in its entirety with the Affordable Clean Energy Rule (the “ACE Rule”), which is aimed at reducing GHG emissions from fossil fueled fired power plants by improving their efficiency. The ACE Rule was published in the Federal Register on August 31, 2018 and the period for public comment extends to October 31, 2018. The outcome of these rulemakings is uncertain and is likely to be subject to an extensive notice and comment process and litigation. Any regulation restricting GHG emissions from the power sector, whether the CPP or any regulation replacing it, could adversely affect the demand for natural gas.

In June 2016, the EPA published new source performance standards (the “2016 Standards”) for methane, identified as a potent GHG, and volatile organic compound emissions from certain new, modified and reconstructed equipment, processes and activities across the oil and natural gas sector. These rules included first-time standards to address emissions of methane from equipment and processes across the source category, including fugitive emissions from well sites and compressors, and equipment leaks at natural gas processing plants. In accordance with the March 2017 Executive Order, the EPA has initiated a review of these standards. In March 2018, the EPA announced amendments to two narrow provisions of the 2016 New Source Performance Standards including removing the requirement for completion of delayed repairs during unscheduled or emergency vent blowdowns under the fugitive emissions provisions. In September 2018, the EPA published proposed revisions to the 2016 Standards which, among other changes, would reduce the required frequency of monitoring surveys at well sites and compressor stations, increase time to complete repairs related to leaks and allow companies operating in certain states to follow state-level standards as an alternative to federal standards. The draft rule is subject to a 60-day comment period beginning from the date of publication in the Federal Register. The outcome of this rulemaking is uncertain.

On the international level, in December 2015, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France which prepared an agreement requiring member countries to review and represent a progression in their intended nationally determined contributions of GHG (the “Paris Agreement”). This agreement set GHG emission reduction goals every five years beginning in 2020, however, it does not create any binding obligations for nations to limit their GHG emissions. The Paris Agreement was signed by the U.S. in April 2016 and entered into force in November 2016. On June 1, 2017, President Trump announced that the U.S. plans to withdraw from the Paris Agreement and will seek negotiations to either re-enter the Paris Agreement under different terms or to establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020 for the U.S. The U.S.’ adherence to the exit process and/or the terms on which the U.S. may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs, or limit emissions of GHGs from our equipment and operations or those that transport,

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process or store our products, could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as cause delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for our products.

In addition, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for our products, or cause us to incur significant costs in preparing for or responding to those effects.

More comprehensive and stringent regulation in the U.S. Gulf of Mexico in the aftermath of the Macondo well oil spill has significantly increased costs and delays in offshore oil and natural gas exploration and production operations.

Following an April 20, 2010 fire and explosion aboard the Deepwater Horizon drilling rig and resulting oil spill from the Macondo well operated by a third party in deepwater in the U.S. Gulf of Mexico, there have been a series of regulatory initiatives developed and implemented at the federal level to address the direct impact of the incident and to prevent similar incidents in the future. Beginning in 2010 and continuing through the present, the Department of Interior (“DOI”) through the BOEM and the BSEE, has issued a variety of regulations and NTLs, intended to impose additional safety, permitting and certification requirements applicable to exploration, development and production activities in the U.S. Gulf of Mexico. These regulatory initiatives effectively slowed down the pace of drilling and production operations in the U.S. Gulf of Mexico as adjustments were being made in operating procedures, certification requirements and lead times for inspections, drilling applications and permits, and exploration and production plan reviews, and as the federal agencies evolved into their present day bureaus.

On April 17, 2015, BSEE published a proposed rule that would impose more stringent standards on blowout preventers (“BOP”). In April 2016, BSEE issued a final version of this rule effective July 2016, though some requirements of the rule have delayed compliance deadlines. The final rule addresses the full range of systems and equipment associated with well control operations, focusing on requirements for BOPs, well design, well control casing, cementing, real-time monitoring and subsea containment. Key features of the well control regulations include requirements for BOPs, double shear rams, third-party reviews of equipment, real time monitoring data, safe drilling margins, centralizers, inspections and other reforms related to well design and control, casing, cementing and subsea containment. On March 28, 2017, President Trump signed an executive order (the “March 2017 Executive Order”) directing federal agencies to initiate rulemakings to suspend, revise or rescind certain regulations relating to the energy industry as necessary to ensure consistency with the goals of energy independence, economic growth and cost-effective environmental regulation. In response to the March 2017 Executive Order and a subsequent executive order issued by President Trump in April 2017 focusing on offshore energy development, in May 2018, BSEE published a proposal to relax certain requirements of the July 2016 rule. The proposed rule is subject to a 60 day comment period and will also likely be subject to legal challenges.

In addition to the array of new or revised safety, permitting and certification requirements developed and implemented by the DOI in the past few years, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production, such as, for example, a proposal to significantly increase the minimum financial responsibility demonstration required under the OPA.

To the extent that the existing regulatory initiatives implemented and pursued over the past few years or any future restrictions, whether through legislative or regulatory means or increased or broadened permitting and enforcement programs, foster uncertainties or delays in our offshore oil and natural gas development or exploration activities, then such conditions may have a material adverse effect on our business, financial condition and results of operations.

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Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act to impose penalties for violations of up to $1 million per day for each violation in addition to disgorgement of unjust profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and Natural Gas Industry.”

Derivatives laws and related regulations and other regulations could have a material adverse effect on our ability to hedge risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the U.S. Commodity Exchange Act (the “CEA”) and U.S. federal securities laws to provide comprehensive federal oversight of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act also mandated that the Commodity Futures Trading Commission (the “CFTC”) adopt regulations that implement the provisions of the Dodd-Frank Act relating to derivatives referred to as “swaps.”

The CEA and CFTC rules generally require certain classes of swaps to be cleared on a derivatives clearing organization and executed on an exchange or execution facility. The CEA, CFTC rules and rules of the federal banking regulators also require swap dealers to exchange margin with certain counterparties when transacting in uncleared swaps. At present, we qualify for exceptions from these requirements for those swaps that we enter into to hedge our commercial risk. However, if we were to fail to qualify for such exceptions, we could become subject to some or all of these requirements, which would increase our cost of entering into and maintaining such hedging positions. Moreover, the application of the clearing, trade execution and margin requirements and other related regulations to our dealer counterparties may change the cost and availability of the swaps that we use for hedging. Certain other requirements, such as reporting and recordkeeping, may also apply to the swaps that we enter into, but these requirements are not expected to have a material impact on us.

In December 2016, the CFTC re-proposed rules that would impose position limits for certain futures and option contracts in specified energy, metals and agricultural commodities (including oil and natural gas) and for swaps that are their economic equivalents, subject to exceptions for certain bona fide hedging transactions. As these proposed position limit rules are not yet final, the impact of these provisions on us is uncertain at this time.

Federal banking regulators have adopted capital requirements for certain regulated financial institutions in connection with the Basel III Accord. If we enter into derivatives with financial institutions that are subject to these capital requirements, the financial institutions could contractually require us to post cash or other collateral to secure our obligations under the derivatives to reduce the amount of capital the financial institutions may be required to maintain with respect to such derivatives. In addition, the financial institutions could price such transactions at a premium to compensate for their additional capital costs relating to such derivatives.

The Dodd-Frank Act, the rules mandated thereby, the proposed position limits rules, and the rules implementing the Basel III Accord capital requirements, among other rules, could significantly increase the cost of derivative contracts and materially reduce our liquidity (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we are limited in our use of derivatives in the future as a result of the Dodd-Frank Act and derivatives regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

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The Trump administration has indicated in public statements that the Dodd-Frank Act will be under scrutiny and that some of its provisions and the rules promulgated thereunder may be revised, repealed or amended. Any such changes, including their nature and impact, cannot yet be determined with any degree of certainty.

In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome.

We face various risks associated with increased activism against oil and natural gas exploration and development activities.

Opposition toward oil and natural gas drilling and development activity has been growing globally. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, delay or cancel certain operations such as offshore drilling and development.

Future activist efforts could result in the following:

• delay or denial of drilling permits;

• shortening of lease terms or reduction in lease size;

• restrictions or delays on our ability to obtain additional seismic data;

• restrictions on installation or operation of gathering or processing facilities;

• restrictions on the use of certain operating practices;

• legal challenges or lawsuits;

• damaging publicity about us;

• increased regulation;

• increased costs of doing business;

• reduction in demand for our products; and

• other adverse effects on our ability to develop our properties.

Uncertainties related to the interpretation and application of recently enacted tax legislation may result in a material adverse effect on our cash tax liabilities, results of operations and financial condition if the Internal Revenue Service (“IRS”) does not agree with our interpretations and assumptions with respect to this new legislation.

On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) significantly revised U.S. federal corporate income tax law by, among other things, reducing the U.S. federal corporate income tax rate to 21%, limiting the tax deduction for interest expense to 30% of adjusted earnings, allowing immediate expensing for certain new investments, and, effective for net operating losses arising in taxable years beginning after December 31, 2017, eliminating net operating loss carrybacks, permitting indefinite net operating loss carryforwards, and limiting the use of net operating loss carryforwards to 80% of current year taxable income.

There are a number of uncertainties and ambiguities as to the interpretation and application of many of the provisions in the Tax Act. In the absence of guidance on these issues, we will use what we believe are reasonable interpretations and assumptions in applying the Tax Act for purposes of determining our cash tax liabilities and

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results of operations, which may change as we receive additional clarification and implementation guidance and as the interpretation of the Tax Act evolves over time. It is possible that the IRS could issue subsequent guidance or take positions on audit that differ from the interpretations and assumptions that we previously made, which could have a material adverse effect on our cash tax liabilities, results of operations and financial condition.

In the past, we have identified material weaknesses in internal control over financial reporting, and we cannot assure you that additional material weaknesses will not be identified in the future. Our failure to implement and maintain effective internal control over financial reporting could result in material misstatements in our financial statements which could require us to restate financial statements, cause investors to lose confidence in our reported financial information and have a negative effect on the price of our Class A common stock.

Currently, we are a private company and have not been required to file reports with the SEC. During 2017, management identified errors in previously issued financial statements. The items identified related to internal controls primarily over the preparation, validation and review of the DD&A expense calculations and full cost ceiling tests and the accounting for our Series A preferred stock issued on December 30, 2016. Management concluded these were material weaknesses in our internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control, such that there is a reasonable possibility that a material misstatement of a company’s financial statements will not be prevented, or detected and corrected on a timely basis. Further, it was determined that we did not have a sufficient number of trained employees for key financial reporting processes and internal controls.

Prior to the issuance of the financial statements for the year ended December 31, 2017, we corrected the errors in the financial statements for the year ended December 31, 2016 and reissued those restated financial statements to the appropriate users. The restated financial statements for the year ended December 31, 2016 were subsequently reflected in the comparative audited financial statements for the years ended December 31, 2017 and 2016 included elsewhere in this prospectus. In addition, we have since remediated the identified material weaknesses by modifying our internal controls to provide additional levels of review, training for staff and enhanced documentation. We have also hired a number of additional staff members, including a more senior, experienced Chief Accounting Officer, an Assistant Controller, a Director of Financial Reporting and a Manager of Technical and Financial Accounting.

However, we cannot assure you that additional material weaknesses in our internal control over financial reporting will not be identified in the future. Any failure to maintain or implement required new or improved controls, or any difficulties we encounter in their implementation, could result in additional material weaknesses, cause us to fail to meet our periodic reporting obligations or result in material misstatements in our financial statements. Any such failure could also adversely affect the results of periodic management evaluations regarding the effectiveness of our internal control over financial reporting. Furthermore, pursuant to Section 404 of the Sarbanes-Oxley Act, we will be required to furnish a report by our management on our internal control over financial reporting, including an attestation report on internal control over financial reporting issued by our independent registered public accounting firm. However, while we remain an emerging growth company, we will not be required to include this attestation report on internal control over financial reporting issued by our independent registered public accounting firm. We could be an emerging growth company for up to five years. An independent assessment of the effectiveness of our internal control over financial reporting could detect problems that our management’s assessment might not. The existence of a material weakness could result in errors in our financial statements that could result in a restatement of financial statements, cause us to fail to meet our reporting obligations and cause investors to lose confidence in our reported financial information, leading to a decline in the price of our Class A common stock.

The loss of senior management or technical personnel could materially adversely affect our operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. We have employment agreements

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with our senior executives which contain restrictions on competition with us in the event they cease to be employed by us. However, as a practical matter, such employment agreements may not assure the retention of our key employees. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

Our business may be adversely affected by information technology system failures, network disruptions and breaches in data security.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, distribution and accounting activities. We depend on digital technologies to interpret seismic data, to manage drilling rigs, production equipment and gathering transportation systems, to conduct reservoir modeling and reserves estimation and to process and record financial and operating data. Pipelines, refineries, power stations and distribution points for both fuels and electricity are also becoming interconnected by computer systems. If any such systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, an inability to find, produce, process and sell oil and natural gas and an inability to automatically process commercial transactions or engage in similar automated or computerized business activities.

We rely heavily on our information systems, and the availability and integrity of these systems are essential for us to conduct our business and operations. We face various security threats, including cybersecurity threats such as attempts to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing facilities, pipelines and refineries; and threats from terrorist acts. Cybersecurity incidents are increasing in frequency, evolving in nature and include, but are not limited to, installation of malicious software, unauthorized access to data and other electronic security breaches that could lead to disruptions in systems, unauthorized release of confidential or otherwise protected information and the corruption of data.

We have experienced cybersecurity incidents in the past, and may experience them in the future. For instance, our employees have been and may continue to be targeted by parties using fraudulent “spoof” and “phishing” emails to misappropriate information or to introduce viruses or other malware programs into our computer systems. These emails appear to be legitimate emails sent by us but direct recipients to fake websites operated by the sender of the email or request that the recipient send a password or other confidential information through email or download malware. One such incident occurred in September 2015, where one or more individuals impersonated a member of senior management by creating email accounts designed to mimic such officer’s email address, and then induced certain of our employees to wire funds to non-Company accounts under the guise of conducting business on behalf of the Company. As a result of this scheme, approximately $1.6 million was improperly transferred from the Company, $1.0 million of which was reimbursed by insurance. Despite our efforts to mitigate such emails (frequently referred to as “spoof” and “phishing” emails) through employee education, such “spoof” and “phishing” activities remain a problem that may damage our information technology infrastructure, compromise our confidential information and/or cause us to suffer financial harm.

While management has taken steps to address cybersecurity concerns by implementing network security and internal control measures to monitor and mitigate security threats and to increase security for our information, facilities, and infrastructure, our implementation of such procedures and controls may result in increased costs, and there can be no assurance that a system failure or data security breach will not occur. Given the unpredictability of the timing, nature and scope of information technology disruptions, there can be no assurance that the above procedures and controls will be sufficient to prevent security breaches from occurring and we could be subject to manipulation or improper use of our systems and networks or financial losses from remedial actions, any of which could have a material adverse effect on our business, financial condition and results of operations.

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In addition to cybersecurity threats, other information system failures and network disruptions could have a material adverse effect on our ability to conduct our business. We could experience system failures due to power or telecommunications failures, human error, natural disasters, fire, sabotage, hardware or software malfunction or defects, computer viruses, intentional acts of vandalism or terrorism and similar acts or occurrences. Such system failures could result in the unanticipated disruption of our operations, communications or processing of transactions, as well as loss of, or damage to, sensitive information, facilities, infrastructure and systems essential to our business and operations, the failure to meet regulatory standards and the delays in reporting of our financial results, and other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial condition and results of operations.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the U.S. or other countries may adversely affect the U.S. and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Changes in generally accepted accounting principles in the U.S. could have a material adverse effect on our previously reported results of operations.

Generally accepted accounting principles in the United States are subject to interpretation by the Financial Accounting Standards Board (“FASB”), the SEC, and various bodies formed to promulgate and to interpret appropriate accounting principles. A change in these principles or interpretations could have a significant effect on our previously reported results of operations and could affect the reporting of transactions completed before the announcement of a change.

In February 2016, the FASB issued ASU No. 2016–02, Leases (Topic 842) (“ASU 2016-02”), which will require lessees to recognize a right of use asset and a lease liability on their balance sheet for all leases, including operating leases, with a term of greater than 12 months. ASU 2016-02 will also require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. We are evaluating the impact the adoption of this ASU may have on our consolidated financial statements and have engaged a third-party specialist to assist in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Standard setting guidance and interpretations continue to evolve and are being monitored for applicability and impact to our business and industry. Based on an initial review of the ASU 2016-02 and our current commitments, we anticipate it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time. It is difficult to predict the exact impact of this or future changes to accounting principles or our accounting policies, any of which could materially adversely affect our results of operations.

Additionally, our assumptions, estimates and judgments related to complex accounting matters could significantly affect our financial results. GAAP and related accounting pronouncements, implementation guidelines and interpretations with regard to a wide range of matters that are relevant to our business, including, but not limited to, revenue recognition, impairment of long-lived assets, intangibles, self-insurance, income taxes, property and equipment, litigation and equity-based compensation are highly complex and involve many subjective assumptions, estimates and judgments by us. Changes in these rules or their interpretation or changes in underlying assumptions, estimates or judgments by us (i) could require us to make changes to our accounting

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systems to implement these changes that could increase our operating costs and (ii) could significantly change our reported or expected financial performance.

Risks Related to Our Organizational Structure

Our principal asset is our interest in EnVen GoM and, accordingly, we depend on distributions from EnVen GoM to pay taxes and expenses, including payments under the tax receivable agreement that we and EnVen GoM are party to with EnVen Equity Holdings (the “Tax Receivable Agreement”). Our ability to make such distributions may be subject to various limitations and restrictions.

We are a holding company and have no material assets other than our ownership of LLC Units of EnVen GoM. As such, we have no independent means of generating revenue or cash flow, and our ability to pay our taxes and operating expenses or declare and pay dividends in the future, if any, will be dependent upon the financial results and cash flows of EnVen GoM and its subsidiaries and distributions we receive from EnVen GoM. There can be no assurance that our subsidiaries will generate sufficient cash flow to distribute funds to us or that applicable state law and contractual restrictions, including negative covenants in our debt instruments, will permit such distributions.

EnVen GoM is treated as a partnership for U.S. federal income tax purposes and, as such, is not subject to any entity-level U.S. federal income tax. Instead, taxable income is allocated to holders of its LLC Units, including us. Accordingly, we will incur income taxes on our allocable share of any net taxable income of EnVen GoM. Under the terms of the EnVen GoM LLC Agreement, EnVen GoM is obligated to make tax distributions to holders of LLC Units, including us. In addition to tax expenses, we will also incur expenses related to our operations, including payments under the Tax Receivable Agreement, which, in the future, could be significant. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.” We intend, as its managing member, to cause EnVen GoM to make cash distributions to the owners of LLC Units, including us, in an amount sufficient to (i) fund all or part of their tax obligations in respect of taxable income allocated to them and (ii) cover our operating expenses, including payments under the Tax Receivable Agreement. However, EnVen GoM’s ability to make such distributions may be subject to various limitations and restrictions, such as restrictions on distributions that would either violate any contract or agreement to which EnVen GoM is then a party, including debt agreements, or any applicable law, or that would have the effect of rendering EnVen GoM insolvent. If we do not have sufficient funds to pay tax or other liabilities or to fund our operations, we may have to borrow additional funds, which could materially adversely affect our liquidity and financial condition and subject us to various restrictions imposed by any such lenders. To the extent that we are unable to make payments under the Tax Receivable Agreement for any reason, such payments generally will be deferred and will accrue interest until paid. However, nonpayment for a specified period may constitute a material breach of a material obligation under the Tax Receivable Agreement and therefore accelerate payments due under the Tax Receivable Agreement. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.” In addition, if EnVen GoM does not have sufficient funds to make distributions, our ability to declare and pay cash dividends will also be restricted or impaired. See “—Risks Related to Ownership of Our Class A Common Stock.”

The Tax Receivable Agreement requires us to make cash payments to holders of LLC Units of EnVen GoM in respect of certain tax benefits to which we may become entitled, and, in the future, we may be required to make substantial payments.

We are a party to the Tax Receivable Agreement with EnVen Equity Holdings for the benefit of the members of EnVen Equity Holdings. Under the Tax Receivable Agreement, we are required to make cash payments to EnVen Equity Holdings or its members, as applicable, equal to 85% of the tax benefits, if any, that we actually realize, or in certain circumstances are deemed to realize, as a result of (1) the increases in the tax basis of assets of EnVen GoM resulting from any redemptions or exchanges of LLC Units from EnVen Equity Holdings and/or its members, or any prior sales of interests in EnVen GoM and (2) certain other tax benefits

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related to our making payments under the Tax Receivable Agreement. The amount of the cash payments that we may be required to make under the Tax Receivable Agreement in the future could be significant. For example, assuming (i) that EnVen Equity Holdings redeemed or exchanged all of its LLC Units immediately after the completion of this offering, (ii) no material changes in relevant tax law, and (iii) that we earn sufficient taxable income in each year to realize on a current basis all tax benefits that are subject to the Tax Receivable Agreement, based on the assumed initial public offering price of $             per share of our Class A common stock, which is the midpoint of the price range set forth on the cover page of this prospectus, we expect that the tax savings we would be deemed to realize would aggregate approximately $             million over the                  -year period from the assumed date of such redemption or exchange, and over such period we would be required to pay EnVen Equity Holdings or its members 85% of such amount, or approximately $             million, over such period. The actual amounts we may be required to pay under the Tax Receivable Agreement may materially differ from these hypothetical amounts, as potential future tax savings we will be deemed to realize, and Tax Receivable Agreement payments by us, will be calculated based in part on the market value of our Class A common stock at the time of redemption or exchange and the prevailing federal tax rates applicable to us over the life of the Tax Receivable Agreement (as well as the assumed combined state and local tax rate), and will generally be dependent on us generating sufficient future taxable income to realize all of these tax savings (subject to the exceptions described below). Any payments made by us to EnVen Equity Holdings or its members under the Tax Receivable Agreement will generally reduce the amount of overall cash flow that might have otherwise been available to us and will generally reduce our earnings that we may have otherwise achieved had the Tax Receivable Agreement not been in place. Furthermore, our future obligation to make payments under the Tax Receivable Agreement could make us a less attractive target for an acquisition, particularly in the case of an acquirer that cannot use some or all of the tax benefits that are the subject of the Tax Receivable Agreement. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.” Payments under the Tax Receivable Agreement are not conditioned on EnVen Equity Holdings’ or any its members’ continued ownership of LLC Units or our Class A common stock after this offering.

The actual amount and timing of any payments under the Tax Receivable Agreement vary depending upon a number of factors, including the timing of redemptions or exchanges by the holders of LLC Units, the price of our Class A common stock at the time of redemptions or exchanges, the amount of gain recognized by such holders of LLC Units, the amount and timing of the taxable income we generate in the future, and the federal tax rates then applicable. To date, we have not made any payments under the Tax Receivable Agreement (as there have not been any redemptions or exchanges of LLC Units from EnVen Equity Holdings and/or its members). As described elsewhere herein, the Tax Receivable Agreement represents a contractual arrangement by which we agree to remit a portion of our cash tax savings resulting from certain equity transactions to the counterparty to those equity transactions. Such cash payments required by the Tax Receivable Agreement will generally be made only if, when, and to the extent that we realize cash tax savings. Such payments would be required to be made in the period in which we realize, or are deemed to realize, the cash tax savings, and the source of cash to make such payments is cash on hand that otherwise would have been retained due to the reduction in our cash taxes resulting from the equity transactions. Payments due pursuant to the Tax Receivable Agreement may be viewed as self-financing because we retain a portion (i.e., 15%) of the cash tax savings resulting from the equity transactions that trigger payments under the Tax Receivable Agreement. Accordingly, we do not anticipate that any payments that may eventually be required to be made pursuant to the Tax Receivable Agreement will require incremental financing beyond the amount otherwise required for us to satisfy our cash flow requirements for income taxes.

Our organizational structure, including the Tax Receivable Agreement, confers certain benefits upon the members of EnVen Equity Holdings that will not benefit Class A common stockholders to the same extent as it will benefit the members of EnVen Equity Holdings.

Our organizational structure, including the Tax Receivable Agreement, confers certain benefits upon the members of EnVen Equity Holdings, directly or indirectly through EnVen Equity Holdings, which will not benefit the holders of our Class A common stock to the same extent as it will benefit the members of EnVen

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Equity Holdings. The Tax Receivable Agreement provides for the payment by us to EnVen Equity Holdings or its members, as applicable, of 85% of the amount of tax benefits, if any, that we actually realize, or in some circumstances, are deemed to realize, as a result of (1) the increases in the tax basis of assets of EnVen GoM resulting from any redemptions or exchanges of LLC Units from EnVen Equity Holdings and/or its members and (2) certain other tax benefits related to our making payments under the Tax Receivable Agreement. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.” Although we will retain 15% of the amount of such tax benefits, this and other aspects of our organizational structure may adversely impact the future trading market for our Class A common stock. In addition, as a result of certain provisions in the EnVen GoM LLC Agreement that are favorable to EnVen Equity Holdings and its members, our ability to derive tax benefits with respect to property previously contributed to EnVen GoM by EnVen Equity Holdings or the members of EnVen Equity Holdings may be significantly limited. See “—Risks Related to Ownership of Our Class A Common Stock.”

In certain cases, payments under the Tax Receivable Agreement to EnVen Equity Holdings or the its members may be accelerated or significantly exceed the actual benefits we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

The Tax Receivable Agreement provides that if (i) we materially breach any of our material obligations under the Tax Receivable Agreement, (ii) certain mergers, asset sales, other forms of business combinations, or other changes of control were to occur or (iii) we elect an early termination of the Tax Receivable Agreement, then our or our successor’s obligations under the Tax Receivable Agreement would accelerate and become due and payable, based on certain assumptions, including an assumption that we would have sufficient taxable income to fully utilize all potential future tax benefits that are subject to the Tax Receivable Agreement.

As a result, (i) we could be required to make payments under the Tax Receivable Agreement that are greater than the specified percentage of the actual benefits we ultimately realize in respect of the tax benefits that are subject to the Tax Receivable Agreement and (ii) we could be required to make an immediate cash payment equal to the present value of the anticipated future tax benefits that are the subject of the Tax Receivable Agreement, which payment may be made significantly in advance of the actual realization, if any, of such future tax benefits. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control. There can be no assurance that we will be able to fund or finance our obligations under the Tax Receivable Agreement. If we were to exercise our right to terminate the Tax Receivable Agreement immediately after this offering, based on the initial public offering price of $             per share of our Class A common stock and a discount rate equal to the lesser of 6.5% and LIBOR plus 100 basis points, we estimate that we would be required to pay $             million in the aggregate under the Tax Receivable Agreement.

We will not be reimbursed for any payments made to EnVen Equity Holdings or its members under the Tax Receivable Agreement in the event that any tax benefits are disallowed.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we determine, and the Internal Revenue Service, or the IRS, or another tax authority may challenge all or part of the tax basis increases, as well as other related tax positions we take, and a court could sustain such challenge. If the outcome of any such challenge would reasonably be expected to materially affect a recipient’s payments under the Tax Receivable Agreement, then the recipient will have the right to participate in and to monitor at its own expense any such challenge. We will not be reimbursed for any cash payments previously made to EnVen Equity Holdings or its members under the Tax Receivable Agreement in the event that any tax benefits initially claimed by us and for which payment has been made to EnVen Equity Holdings or its members are subsequently challenged by a taxing authority and are ultimately disallowed. Instead, any excess cash payments made by us to EnVen Equity Holdings or its members will be netted against any future cash payments that we might otherwise be required to make to EnVen Equity Holdings or such member under the terms of the Tax Receivable

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Agreement. However, we might not determine that we have effectively made an excess cash payment to EnVen Equity Holdings or its members for a number of years following the initial time of such payment and, if any of our tax reporting positions are challenged by a taxing authority, we will not be permitted to reduce any future cash payments under the Tax Receivable Agreement until any such challenge is finally settled or determined. As a result, payments could be made under the Tax Receivable Agreement in excess of the tax savings that we realize in respect of the tax attributes with respect to EnVen Equity Holdings or its members that are the subject of the Tax Receivable Agreement.

We are substantially influenced by our significant equity investors.

After giving effect to the consummation of this offering, entities affiliated with Bain Capital Credit (“Bain”), Adage Capital Partners, L.P. and EIG Global Energy Partners will beneficially own approximately      %,     % and     % of the combined voting power of our common stock through their ownership of both Class A common stock and Class B common stock (reflecting the inclusion of the Series A preferred stock on an as-converted-to-common basis at a conversion price based on initial issue price of $12.00). As such, our significant equity investors have significant influence over corporate management and affairs. It is possible that the interests of the significant equity investors may in some circumstances conflict with our interests. For example, the significant equity investors may have different tax positions from us, especially in light of the Tax Receivable Agreement, that could influence their decisions regarding whether and when to support the disposition of assets, the incurrence or refinancing of new or existing indebtedness, or the termination of the Tax Receivable Agreement and the acceleration of our obligations thereunder. In addition, the determination of future tax reporting positions, the structuring of future transactions and the handling of any challenge by any taxing authority to our tax reporting positions may take into consideration the significant equity investors’ tax or other considerations which may differ from the considerations of us or our other stockholders. Please read “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

In addition, certain of the significant equity investors are in the business of making or advising on investments in companies and may hold, and may from time to time in the future, acquire interests in or provide advice to businesses that directly or indirectly compete with certain portions of our business. EnVen’s certificate of incorporation provides that, to the fullest extent permitted by law, none of the significant equity investors or any director who is not employed by us or his or her affiliates will have any duty to refrain from engaging in a corporate opportunity in the same or similar lines of business as us. The significant equity investors may also pursue acquisitions that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us.

Presently and at any time following the consummation of this offering, the members of EnVen Equity Holdings will have the right to have their LLC Units redeemed pursuant to the terms of the EnVen GoM LLC Agreement.

Under the terms of the EnVen GoM LLC Agreement, the holders of LLC Units in EnVen GoM will be entitled to have their LLC Units redeemed for cash or, under certain circumstances, shares of our Class A common stock. We have also entered into a registration rights agreement pursuant to which the shares of Class A common stock issued to the members of EnVen Equity Holdings upon redemption of LLC Units will be eligible for resale, subject to certain limitations set forth therein. Please read “Certain Relationships and Related Party Transactions—Registration Rights Agreements.”

In certain circumstances, EnVen GoM will be required to make distributions to us and the other holders of LLC Units, and the distributions that EnVen GoM will be required to make may be substantial.

Under the EnVen GoM LLC Agreement, EnVen GoM will generally be required from time to time to make pro rata distributions in cash to us and the other holders of LLC Units in amounts that are intended to be sufficient to cover the taxes on our and the other LLC Units holders’ respective allocable shares of the taxable

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income of EnVen GoM. As a result of (i) potential differences in the amount of net taxable income allocable to us and the other LLC Unit holders, (ii) the lower tax rate applicable to corporations than individuals and (iii) the favorable tax benefits that we anticipate receiving from (a) acquisitions of interests in EnVen GoM in connection with future taxable redemptions or exchanges of LLC Units for shares of our Class A common stock and (b) payments under the Tax Receivable Agreement, we expect that these tax distributions will be in amounts that exceed our tax liabilities and obligations to make payments under the Tax Receivable Agreement. Our board of directors will determine the appropriate uses for any excess cash so accumulated, which may include, among other uses, dividends, the payment of obligations under the Tax Receivable Agreement and the payment of other expenses. We will have no obligation to distribute such cash (or other available cash other than any declared dividend) to our stockholders. No adjustments to the redemption or exchange ratio of LLC Units for shares of Class A common stock will be made as a result of either (i) any cash distribution by us or (ii) any cash that we retain and do not distribute to our shareholders. To the extent that we do not distribute such excess cash as dividends on our Class A common stock and instead, for example, hold such cash balances or lend them to EnVen GoM, the members of EnVen Equity Holdings would benefit from any value attributable to such cash balances as a result of their ownership of Class A common stock following a redemption or exchange of their LLC Units. See “Certain Relationships and Related Party Transactions—EnVen GoM LLC Agreement.”

Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our operating results and financial condition.

We are subject to income taxes in the United States, and our tax liabilities will be subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

• changes in the valuation of our deferred tax assets and liabilities;

• expected timing and amount of the release of any tax valuation allowances;

• tax effects of stock-based compensation; or

• changes in tax laws, regulations or interpretations thereof.

In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our operating results and financial condition.

If we were deemed to be an investment company under the Investment Company Act of 1940, as amended (the “1940 Act”), as a result of our ownership of EnVen GoM, applicable restrictions could make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business, financial condition and results of operations.

Under Sections 3(a)(1)(A) and (C) of the 1940 Act, a company generally will be deemed to be an “investment company” for purposes of the 1940 Act if (i) it is, or holds itself out as being, engaged primarily, or proposes to engage primarily, in the business of investing, reinvesting or trading in securities or (ii) it engages, or proposes to engage, in the business of investing, reinvesting, owning, holding or trading in securities and it owns or proposes to acquire investment securities having a value exceeding 40% of the value of its total assets (exclusive of U.S. government securities and cash items) on an unconsolidated basis. We do not believe that we are an “investment company,” as such term is defined in either of those sections of the 1940 Act.

As the managing member of EnVen GoM, we will control and operate EnVen GoM. On that basis, we believe that our interest in EnVen GoM is not an “investment security” as that term is used in the 1940 Act. However, if we were to cease participation in the management of EnVen GoM, our interest in EnVen GoM could be deemed an “investment security” for purposes of the 1940 Act.

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We and EnVen GoM intend to conduct our operations so that we will not be deemed an investment company. However, if we were to be deemed an investment company, restrictions imposed by the 1940 Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to Ownership of Our Class A Common Stock

The requirements of being a U.S. public company require significant resources and management attention and affect our ability to attract and retain executive management and qualified board members.

As a U.S. public company following this offering, we will incur legal, accounting, and other expenses that we did not previously incur. We will be subject to the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including the reporting requirements thereunder, the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, the NYSE listing requirements and other applicable securities rules and regulations. Compliance with these rules and regulations will increase our legal and financial compliance costs, make some activities more difficult, time-consuming or costly and increase demand on our systems and resources, particularly after we are no longer an “emerging growth company.”

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”), we will be required to furnish a report by our management on our internal control over financial reporting, including an attestation report on internal control over financial reporting issued by our independent registered public accounting firm. However, while we remain an emerging growth company, we will not be required to include this attestation report on internal control over financial reporting issued by our independent registered public accounting firm. When our independent registered public accounting firm is required to undertake an assessment of our internal control over financial reporting, the cost of complying with Section 404 will significantly increase and management’s attention may be diverted from other business concerns, which could materially adversely affect our business and results of operations. We may need to hire more employees in the future or engage outside consultants to comply with these requirements, which will further increase our cost and expense. If we fail to implement the requirements of Section 404 in the required timeframe, we may be subject to sanctions or investigations by regulatory authorities, including the SEC and the NYSE. Furthermore, if we are unable to conclude that our internal control over financial reporting is effective, we could lose investor confidence in the accuracy and completeness of our financial reports, the market price of shares of our Class A common stock could decline, and we could be subject to sanctions or investigations by regulatory authorities. Failure to implement or maintain effective internal control systems required of public companies could also restrict our future access to the capital markets. In addition, enhanced legal and regulatory regimes and heightened standards relating to corporate governance and disclosure for public companies result in increased legal and financial compliance costs and make some activities more time consuming.

We expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

An active trading market for our Class A common stock may not develop, and the market price for our Class A common stock may be volatile or may decline regardless of our operating performance.

Prior to the completion of this offering, there has been no public market for our Class A common stock. An active trading market for shares of our Class A common stock may never develop or be sustained following this offering. If an active trading market does not develop, you may have difficulty selling your shares of our Class A

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common stock at an attractive price, or at all. The price for our Class A common stock in this offering will be determined by negotiations between us and the representatives of the underwriters, and it may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell your Class A common stock at or above the initial public offering price or at any other price or at the time that you would like to sell. An inactive market may also impair our ability to raise capital by selling our Class A common stock, and it may impair our ability to attract and motivate our employees through equity incentive awards and our ability to acquire other companies, products or technologies by using our Class A common stock as consideration.

The price of our Class A common stock may fluctuate substantially or may decline regardless of our operating performance, and you may not be able to resell your shares at or above the public offering price.

You should consider an investment in our Class A common stock to be risky, and you should invest in our Class A common stock only if you can withstand a significant loss and wide fluctuations in the market value of your investment. Some factors that may cause the market price of our Class A common stock to fluctuate, in addition to the other risks mentioned in this section of the prospectus, are:

• our operating and financial performance, including reserve estimates;

• quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

• the public reaction to our press releases, our other public announcements and our filings with the SEC;

• strategic actions by our competitors;

• changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

• speculation in the press or investment community;

• the failure of research analysts to cover our Class A common stock;

• sales of our Class A common stock by us, our directors or officers or the perception that such sales may occur;

• our payment of dividends;

• changes in accounting principles, policies, guidance, interpretations or standards;

• additions or departures of senior management or key personnel;

• actions by our stockholders;

• announcements related to litigation or actions by various regulators;

• default on our indebtedness;

• future issuances of our capital stock or other securities;

• general market conditions, including fluctuations in commodity prices;

• domestic and international economic, legal and regulatory factors unrelated to our performance; and

• the realization of any risks described under this “Risk Factors” section.

These and other market and industry factors may cause the market price and demand for our Class A common stock to fluctuate substantially, regardless of our actual operating performance, which may limit or prevent investors from readily selling their Class A common stock and may otherwise negatively affect the liquidity of our Class A common stock. In addition, the stock market in general has experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies.

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If you purchase shares of Class A common stock in this offering, you will suffer immediate dilution of your investment.

The initial public offering price of our Class A common stock will be substantially higher than the net tangible book value per share of our Class A common stock. Therefore, if you purchase shares of our Class A common stock in this offering, you will pay a price per share that substantially exceeds our net tangible book value per share after this offering. To the extent shares subsequently are issued under outstanding options or warrants, you will incur further dilution. Based on the initial public offering price of $            per share, you will experience immediate dilution of $            per share, representing the difference between our pro forma net tangible book value per share, after giving effect to this offering, and the assumed initial public offering price. If the underwriters exercise their option to purchase additional shares of our Class A common stock, or if outstanding options to purchase our Class A common stock are exercised, you will experience additional dilution. You may experience additional dilution upon future equity issuances or the exercise of stock options to purchase Class A common stock granted to our employees, executive officers and directors under our 2015 Plan or other equity incentive plans. See “Dilution.”

A significant portion of our total outstanding shares are eligible to be sold into the market in the near future, which could cause the market price of our Class A common stock to drop significantly, even if our business is doing well.

Sales of a substantial number of shares of our Class A common stock in the public market, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of our Class A common stock. After this offering, we will have outstanding                shares of Class A common stock (or                shares if the underwriters exercise their option to purchase additional shares in full), including shares issuable upon conversion of the Series A preferred stock in connection with this offering. In addition, approximately              shares of Class A common stock are issuable upon redemption of LLC Units that are held by EnVen Equity Holdings and approximately                      shares of Class A common stock are issuable upon exercise of currently outstanding warrants. Under the terms of the EnVen GoM LLC Agreement, the holders of LLC Units in EnVen GoM are entitled to have their LLC Units redeemed for shares of our Class A common stock or cash, at our election. In addition, see “Prospectus Summary—Our Organizational Structure ” for a discussion of our outstanding warrants. The shares that we are selling in this offering may be resold in the public market immediately without restriction, unless purchased by our affiliates or existing stockholders. Substantially all of the remaining                 shares outstanding are currently restricted as a result of securities laws or lock-up agreements but will become eligible to be sold at various times beginning days after this offering. Moreover, after this offering, holders of an aggregate of approximately                shares of our Class A common stock will have rights, subject to specified conditions, to require us to file registration statements covering their shares or to include their shares in registration statements that we may file for ourselves or other stockholders. We also intend to register all shares of Class A common stock that we may issue under our equity compensation plans. Once we register these shares, they can be freely sold in the public market upon issuance, subject to volume limitations applicable to affiliates and the lock-up agreements described in the “Underwriting” section of this prospectus.

We are an “emerging growth company,” and the reduced disclosure requirements applicable to emerging growth companies may make our Class A common stock less attractive to investors.

We are an “emerging growth company,” as defined in the JOBS Act and may remain an emerging growth company for up to five years. For so long as we remain an emerging growth company, we are permitted and intend to rely on exemptions from certain disclosure requirements that are applicable to other public companies that are not emerging growth companies. These exemptions include:

• being permitted to present only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in this prospectus;

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• not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, in the assessment of our internal control over financial reporting;

• reduced disclosure obligations regarding executive compensation in our periodic reports, proxy statements and registration statements; and

• exemption from the requirements of holding a nonbinding advisory vote on executive compensation and obtaining stockholder approval of any golden parachute payments not previously approved.

We have taken advantage of reduced reporting burdens in this prospectus. In particular, in this prospectus, we have provided only two years of audited financial statements and have not included all of the executive compensation related information that would be required if we were not an emerging growth company. We cannot predict whether investors will find our Class A common stock less attractive if we rely on these exemptions. If some investors find our Class A common stock less attractive as a result, there may be a less active trading market for our Class A common stock and our stock price may be reduced or more volatile. In addition, the JOBS Act provides that an emerging growth company can take advantage of an extended transition period for complying with new or revised accounting standards. This allows an emerging growth company to delay the adoption of these accounting standards until they would otherwise apply to private companies. We have irrevocably elected not to avail ourselves of this exemption and, therefore, we will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

If securities or industry analysts do not publish or cease publishing research or reports about our business, or if they issue an adverse or misleading opinion regarding our stock, our stock price and trading volume could decline.

The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. We do not currently have and may never obtain research coverage by securities and industry analysts. If no or few securities or industry analysts commence coverage of us, the trading price for our Class A common stock would be negatively impacted. In the event we obtain securities or industry analyst coverage, if any of the analysts who cover us issue an adverse or misleading opinion regarding us, our business model or our stock performance, or if our results of operations fail to meet the expectations of analysts, our stock price would likely decline. If one or more of these analysts cease coverage of us or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline.

Because we expect to be a United States real property holding corporation, non-U.S. holders may be subject to U.S. federal income tax in connection with the disposition of shares of our Class A common stock.

A non-U.S. holder of our Class A common stock not otherwise subject to U.S. federal income tax on gain from the sale or other disposition of our Class A common stock may nevertheless be subject to U.S. federal income tax with respect to such sale or other disposition if we are a United States real property holding corporation at any time within the five-year period preceding the sale or other disposition (or the non-U.S. holder’s holding period, if shorter). Generally, a corporation is a United States real property holding corporation if the fair market value of its “United States real property interests,” as defined in the Internal Revenue Code of 1986, as amended, and applicable Treasury Regulations, equals or exceeds 50% of the aggregate fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe we are, and will be in the foreseeable future, a United States real property holding corporation. Accordingly, if either (1) our Class A common stock is not regularly traded on an established securities market during the calendar year in which the sale or disposition occurs or (2) the non-U.S. holder has owned or is deemed to have owned, at any time within the relevant period, more than 5% of our Class A common stock, the non-U.S. holder may be subject to tax on the net gain from the sale or other disposition under the regular graduated U.S. federal income tax rates applicable to U.S. persons and could, under certain circumstances, be subject to withholding at a 15% rate on the amount realized on such sale or other disposition. See “Material U.S. Federal Tax Considerations for Non-U.S. Holders of Class A Common Stock.”

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We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.

Our historical financial data may not be a reliable indicator of our future results.

As a public company, our cost structure will be different and will include both additional recurring costs and nonrecurring costs that we will incur during our transition to being a public company. Accordingly, our historical consolidated financial information may not be reflective of our financial position, results of operations or cash flows or costs had we been a public company during the periods presented, and the historical financial information may not be a reliable indicator of what our financial position, results of operations or cash flows will be in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Provisions in our amended and restated certificate of incorporation and amended and restated bylaws and under Delaware law could make an acquisition of our company, which may be beneficial to our stockholders, more difficult and may prevent attempts by our stockholders to replace or remove our current management.

Provisions in our amended and restated certificate of incorporation and our amended and restated bylaws that will become effective upon the closing of this offering may discourage, delay or prevent a merger, acquisition or other change in control of our company that stockholders may consider favorable, including transactions in which you might otherwise receive a premium for your shares, including:

• limitations on the removal of directors;

• our classified board of directors, under which a director only comes up for election once every three years;

• limitations on the ability of our stockholders to call special meetings;

• establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;

• providing that the board of directors is expressly authorized to adopt, or to alter or repeal our amended and restated bylaws; and

• establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

These provisions could also limit the price that investors might be willing to pay in the future for shares of our Class A common stock, thereby depressing the market price of our Class A common stock.

In addition, because our board of directors is responsible for appointing the members of our management team, these provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our board of directors. The provisions in our amended and restated certificate of incorporation and amended and restated bylaws that could discourage, delay or prevent an unsolicited change in control of our company include board authority to issue preferred stock without stockholder approval.

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Furthermore, in connection with this offering, we will enter into a shareholders agreement with certain of our shareholders affiliated with Bain Capital Credit (the “Bain Investors”). The shareholders agreement provides the Bain Investors with the right to nominate a certain number of nominees to our board of directors so long as the Bain Investors and their affiliates collectively beneficially own at least 10% of the outstanding shares of our Class A common stock. See “Certain Relationships and Related Party Transactions—Shareholders Agreement.”

In addition, our amended and restated certificate of incorporation will provide that we are not governed by Section 203 of the DGCL which, in the absence of such provisions, would impose additional requirements regarding mergers and other business combinations. See “Description of Capital Stock—Our Certificate of Incorporation and Bylaws.”

Our bylaws include exclusive forum, venue and jurisdiction provisions. By purchasing a share of our Class A common stock, a shareholder is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. Our bylaws also provide that any shareholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful claim.

Our amended and restated bylaws will be governed by Delaware law. Our bylaws include exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. Please read “Description of Capital Stock—Exclusive Venue.” If a dispute were to arise between a shareholder and us or our officers, directors or employees, the shareholder may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. In addition, if any shareholder brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. By purchasing a share of our Class A common stock in this offering, a shareholder is irrevocably consenting to these provisions and potential reimbursement obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

Our ability to pay dividends may be restricted by the terms of our Revolving Credit Facility and 2023 Notes.

Following our initial public offering, we will consider paying a cash dividend on our Class A common stock. In the event we decide to pay dividends in the future, our ability to pay dividends may be limited by covenants in our Revolving Credit Facility and the indenture governing our 2023 Notes. Additionally, we are a holding company and have no material assets other than our ownership of LLC Units of EnVen GoM. As such, we have no independent means of generating revenue or cash flow, and our ability to declare and pay dividends in the future is dependent upon the financial results and cash flows of EnVen GoM and its subsidiaries and distributions we receive from EnVen GoM. Any future determination to pay dividends to holders of our Class A common stock will depend on our results of operations, financial condition, capital requirements, contractual restrictions and any other factors that our board of directors may deem relevant, and we can provide no assurance that we will continue to pay dividends to our shareholders following completion of this offering. See “Dividend Policy.”

We could be subject to securities class action litigation.

In the past, securities class action litigation has often been brought against a company following a decline in the market price of its securities. If we face such litigation, it could result in substantial costs and a diversion of management’s attention and resources, which could have a material adverse effect on our business, financial condition or results of operations.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

We have made statements under the captions “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and in other sections of this prospectus that are forward-looking statements. In some cases, you can identify these statements by forward-looking words such as “may,” “might,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue,” the negative of these terms and other comparable terminology. These forward-looking statements, which are subject to risks, uncertainties and assumptions about us, may include projections of our future financial performance, our anticipated growth strategies and anticipated trends in our business. These statements are only predictions based on our current expectations and projections about future events. There are important factors, many of which are beyond our control, that could cause our actual results, level of activity, performance or achievements to differ materially from the results, level of activity, performance or achievements expressed or implied by the forward-looking statements, including those factors discussed under the caption entitled “Risk Factors.” You should specifically consider the numerous risks outlined under “Risk Factors.”

Forward-looking statements may include statements about:

• the volatility of oil and natural gas prices;

• potential write-downs of the carrying value of our oil and natural gas properties if oil and natural gas prices decline;

• potential financial losses or earnings reductions from our derivative activities;

• our future acquisitions and the impact of any such acquisitions;

• the possibility that we may be unable to make attractive acquisitions or successfully integrate acquired businesses;

• any title defects in properties in which we invest;

• the substantial capital expenditures necessary for our exploitation and development projects;

• risks associated with oil and natural gas exploration and production operations;

• uncertainty with respect to our reserves;

• any inability to replace our reserves with new reserves;

• uncertainties associated with the long-term nature of drilling, including the potential inability to raise the substantial amount of capital that may be necessary;

• the risk that we may incur substantial losses and be subject to substantial liability claims as a result of our operations, which we may not be adequately insured for, if at all;

• extreme weather conditions affecting our ability to conduct drilling activities;

• risks associated with operating in one major geographic area, as our properties are all located on the outer continental shelf and deepwater of the U.S. Gulf of Mexico;

• conservation plans and technological measures reducing demand for oil and natural gas;

• our dependence upon a single customer for a substantial majority of our revenue;

• competition within the oil and natural gas industry;

• the fact that the marketability of our production is dependent upon transportation and other facilities operated by third parties, the capacity and operation of which we do not control;

• the unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services;

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• the possibility that we may not be able to keep pace with technological developments in our industry;

• risks, costs and liabilities related to the complex U.S. federal, state, local and other laws and regulations, including regarding tax, environmental, health, and safety issues, and derivatives that we are subject to;

• increased activism against oil and natural gas exploration and development activities;

• our retention of key employees;

• risks, costs and liabilities relating to a failure of our information systems or computer-based technology, or security threats, including cybersecurity threats and other disruptions;

• the occurrence of terrorist attacks aimed at our facilities or operations;

• the volatility of our stock price;

• the increased time and costs associated with operating as a public company;

• our ability to establish and maintain effective internal controls;

• other factors discussed under “Risk Factors” and elsewhere in this prospectus; and

• our plans, objectives, expectations and intentions contained in this prospectus that are not historical.

Although we believe the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, level of activity, performance or achievements. Moreover, neither we nor any other person assumes responsibility for the accuracy and completeness of any of these forward-looking statements. We are under no duty to update any of these forward-looking statements after the date of this prospectus to conform our prior statements to actual results or revised expectations.

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USE OF PROCEEDS

We estimate that the net proceeds to us from this offering will be approximately $         million, or approximately $         million if the underwriters exercise their option to purchase additional shares in full, assuming an initial public offering price of $         per share (the midpoint of the range set forth on the cover page of this prospectus), after deducting estimated underwriting discounts and commissions and estimated offering expenses.

We intend to use the net proceeds from this offering to purchase      LLC Units directly from EnVen GoM at a price per unit equal to the initial public offering price per share of Class A common stock in this offering less the underwriting discounts and commissions.

EnVen GoM anticipates that it will use the $         million in net proceeds it receives from the sale of LLC Units to us (together with any additional proceeds we may receive if the underwriters exercise their option to purchase additional shares of Class A common stock, which will be used to purchase additional LLC Units from EnVen GoM) to redeem up to 35% of the aggregate principal amount of the 2023 Notes at a redemption price equal to 111.0% of the 2023 Notes to be redeemed plus accrued and unpaid interest, pursuant to the terms of the indenture governing the 2023 Notes. As of June 30, 2018, $325 million of the 2023 Notes were outstanding. The 2023 Notes have a stated maturity of February 15, 2023 and accrue interest at a rate equal to 11.0% per annum. This prospectus does not constitute a notice of redemption or an obligation to issue a notice of redemption for the 2023 Notes.

On October 6, 2016, we entered into an engagement letter (the “Engagement Letter”) with FBR Capital Markets & Co. (“FBR”) giving FBR the right to act as the lead underwriter and bookrunner for our initial public offering. If a different lead underwriter is appointed, FBR is entitled to a fee equal to that of the highest paid bookrunner in the underwriting syndicate of our initial public offering. On June 1, 2017, B. Riley Financial, Inc. merged with FBR establishing B. Riley FBR, Inc. As a result of the merger, on May 31, 2018, in conjunction with our Annual General Meeting, we elected not to utilize B. Riley FBR, Inc. as the lead underwriter as provided in the Engagement Letter.

We intend to use any remaining proceeds from this offering for general corporate purposes, including to expand our current business through acquisitions of, or investments in, other businesses, products or technologies. However, we have no commitments with respect to any such acquisitions or investments at this time.

Our management will have broad discretion in the application of the net proceeds from this offering used for general corporate purposes, and investors will be relying on the judgment of our management regarding the application of the proceeds. Pending their use, we may invest such net proceeds from this offering in short-term, interest-bearing obligations, investment-grade instruments, certificates of deposit or direct or guaranteed obligations of the U.S. government.

Each $1.00 increase (decrease) in the assumed initial public offering price per share of $        per share, based on the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) the net proceeds by $        million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us. An increase (decrease) of 1,000,000 shares from the expected number of shares to be sold by us in this offering, assuming no change in the assumed initial offering price per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) the net proceeds from this offering by $         million.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2018:

• on an actual basis (as adjusted to give effect to the Stock Split);

• on an as adjusted basis to reflect (1) the automatic conversion of all outstanding shares of our preferred stock into            shares of our Class A common stock upon the closing of this offering, (2) our issuance and sale of            shares of our Class A common stock in this offering at the initial public offering price of $        per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us and (3) our use of the net proceeds from this offering as described under “Use of Proceeds” in this prospectus.

You should read this information in conjunction with our audited consolidated financial statements as of and for the years ended December 31, 2017 and 2016 and the related notes, our unaudited consolidated financial statements as of and for the three and six months ended June 30, 2018 and 2017 and the related notes and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section, as well as, other financial information, each of which appears elsewhere in this prospectus.

	As of June 30, 2018
(In thousands, except number of shares and par value)	Actual			As Adjusted
Cash and cash equivalents(1)	$	91,515
Long-term debt:
Revolving Credit Facility(2)		—
11.00% Senior notes due 2023(3)	$	352,830
Total long-term debt	$	352,830
Equity(4):
Accumulated deficit	$	(92,304	)
Stockholders’ equity:
Series A convertible perpetual preferred stock, par value $0.001; 25,000,000 shares authorized and 9,998,711 shares issued and outstanding as of June 30, 2018 actual; no shares authorized, issued or outstanding, as adjusted	$	10
Class A common stock, par value $0.001;              shares authorized and              issued and outstanding(5)	$	16
Class B common stock, par value $0.001;              shares authorized and              issued and outstanding(5)	$	3
Additional paid-in capital	$	295,285
Total stockholders’ equity	$	203,010
Non-controlling interest	$	26,413
Total equity	$	229,423
Total capitalization	$	582,253

(1) Does not include current portion of restricted cash as of June 30, 2018 of approximately $9.4 million reserved as cash collateral for certain bonding requirements. Restricted cash includes amounts held in escrow for plugging and abandonment obligations.

(2) At June 30, 2018, we had no outstanding borrowings under our Revolving Credit Facility and availability of $271.4 million (after giving effect to $3.6 million of outstanding letters of credit).

(3) Due to the fair value option election, the 2023 Notes are presented at their fair value as of June 30, 2018.

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(4) As of June 30, 2018, we had Series A Warrants and Series B Warrants outstanding, each of which was exercisable to purchase              shares of Class A common stock (giving effect to the Stock Split). Series A Warrants have the exercise price of $12.50 for one share of Class A common stock and Series B Warrants have the exercise price of $15.00 for one share of Class A common stock. See “Prospectus Summary—Our Organizational Structure” for a discussion of our outstanding warrants.

(5) As adjusted to give effect to the Stock Split.

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DIVIDEND POLICY

Following our initial public offering, we will consider paying a cash dividend on our Class A common stock. Any decision relating to the declaration, amount and payment of any future dividends on shares of Class A common stock is at the sole discretion of our board of directors. Our board of directors may take into account general and economic conditions, our financial condition and operating results, our available cash and current and anticipated cash needs, capital requirements, contractual, legal, tax and regulatory restrictions, including restrictive covenants contained in our financing agreements, implications on the payment of dividends by us to our stockholders or by our subsidiaries to us, and such other factors as our board of directors may deem relevant. We have not declared or paid any dividends on our Class A common stock since our inception. Our ability to pay dividends may be limited by covenants in our Revolving Credit Facility and the indenture governing our 2023 Notes.

We are a holding company and have no material assets other than our ownership of LLC Units of EnVen GoM. As such, we have no independent means of generating revenue or cash flow, and our ability to declare and pay dividends in the future is dependent upon the financial results and cash flows of EnVen GoM and its subsidiaries and distributions we receive from EnVen GoM.

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DILUTION

If you invest in shares of our Class A common stock, your investment will be immediately diluted to the extent of the difference between the initial public offering price per share of Class A common stock and the pro forma as adjusted net tangible book value per share of Class A common stock after this offering. Dilution results from the fact that the per share offering price of the shares of Class A common stock is substantially in excess of the pro forma as adjusted net tangible book value per share attributable to our pre-IPO owners. We have presented dilution in pro forma as adjusted net tangible book value per share of Class A common stock after giving effect to this offering assuming that all of the holders of LLC Units (other than us) had their LLC Units redeemed in exchange for newly-issued shares of Class A common stock on a one-for-one basis in order to more meaningfully present the dilutive impact on the investors in this offering.

After giving effect to the Stock Split, our pro forma net tangible book value as of June 30, 2018 was $         or $        per share of Class A common stock. Pro forma net tangible book value per share of Class A common stock represents tangible assets, less liabilities, divided by the aggregate number of shares of Class A common stock outstanding after giving effect to the automatic conversion of all outstanding shares of our preferred stock into            shares of our Class A common stock (after giving effect to the Stock Split) upon the closing of this offering and the redemption by all of the holders of LLC Units (other than us) of their LLC Units in exchange for newly-issued shares of Class A common stock on a one-for-one basis.

After giving effect to the sale by us of the                  shares of Class A common stock in this offering, at an assumed initial public offering price of $         per share, the midpoint of the range set forth on the cover page of this prospectus, and the receipt and application of the net proceeds, our pro forma as adjusted net tangible book value estimated as of June 30, 2018 would have been approximately $         or $         per share of Class A common stock (after giving effect to the Stock Split). This represents an immediate increase in pro forma net tangible book value to existing stockholders of $         per share and an immediate dilution in net tangible book value of $        per share to new investors. Dilution per share represents the difference between the price per share to be paid by new investors for the shares of Class A common stock sold in this offering and the net tangible book value per share immediately after this offering. The following table illustrates this per share dilution assuming the underwriters do not exercise their option to purchase additional shares of our Class A common stock:

Assumed initial public offering price per share of Class A common stock	$
Pro forma net tangible book value per share of Class A common stock (after giving effect to the Stock Split)
Increase in pro forma net tangible book value per share of Class A common stock attributable to this offering
Pro forma as adjusted net tangible book value per share of Class A common stock after giving effect to this offering (after giving effect to the Stock Split)
Dilution per share of Class A common stock to new investors	$

A $1.00 increase or decrease in the assumed initial public offering price per share of $        per share, the midpoint of the price range set forth on the cover page of this prospectus, would increase or decrease total consideration paid to us by new investors and total consideration paid to us by all stockholders by approximately $        . An increase (decrease) of 1,000,000 in the number of shares offered by us would increase (decrease) total consideration paid by new investors, total consideration paid by all stockholders and average price per share paid by all stockholders by $        , $        and $        per share, respectively. To the extent that we grant stock options to our employees in the future and those stock options are exercised or other issuances of Class A common stock are made, there will be further dilution to new investors.

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The following table sets forth, on a pro forma basis, as of June 30, 2018:

• the number of shares of Class A common stock purchased from EnVen in this offering and the number of shares issued to holders of LLC Units other than us assuming they redeemed all of their LLC Units in exchange for shares of Class A common stock,

• the total consideration paid, or to be paid, by the investors purchasing shares in this offering and by such holders of LLC Units and

• the average price per share paid, or to be paid, by existing stockholders and by the new investors in this offering and by such holders of LLC Units,

based upon the assumed initial public offering price of $     per share, the midpoint of the range set forth on the cover page of this prospectus, before deducting estimated underwriting discounts and commissions and offering expenses payable by EnVen.

	Shares Purchased				Total Consideration				Average Price Per Share
	Number	Percent			Amount	Percent
Existing stockholders				%	$			%
New investors
Total			100	%	$		100	%

The foregoing tables assume no exercise of the underwriters’ option to purchase additional shares or outstanding stock options after June 30, 2018. As of June 30, 2018,              shares of Class A common stock were subject to outstanding options, at a weighted average exercise price of $        . To the extent these options are exercised there will be further dilution to new investors.

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table sets forth our selected historical consolidated financial data for the periods and as of the dates indicated. The selected consolidated financial data as of and for each of the fiscal years ended December 31, 2017 and 2016 have been derived from our audited consolidated financial statements included elsewhere in this prospectus. The selected consolidated balance sheet data as of June 30, 2018 and the summary consolidated statement of operations data, statement of cash flows data and other financial data for each of the six months ended June 30, 2018 and 2017 have been derived from our unaudited consolidated financial statements, which have been prepared on a basis consistent with the audited consolidated financial statements and are included elsewhere in this prospectus.

In the opinion of management, the unaudited consolidated financial statements reflect all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly in all material respects our financial position and results of operations for those periods. Historical results are not necessarily indicative of future expected results and the results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.

The following selected historical consolidated financial data should be read in conjunction with the information included under the headings “Summary Historical Consolidated Financial Data,” “Use of Proceeds,” “Capitalization” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited and unaudited consolidated financial statements and the related notes included elsewhere in this prospectus.

(In thousands, except for the number of shares outstanding and per share amounts)	Six months ended June 30,						Year ended December 31,
	2018			2017			2017			2016
Statement of operations
Total revenues(1)	$	306,094		$	216,373		$	434,411		$	203,319
Operating expenses(1):
Lease operating expenses		41,967			54,510			97,560			67,918
Workover, repair, and maintenance expenses		11,985			8,829			18,642			12,754
Transportation, gathering, and processing costs(2)		5,265			—			—			—
Depreciation, depletion, and amortization		96,473			88,911			170,372			104,584
General and administrative expenses		24,820			19,617			42,397			35,078
Accretion of asset retirement obligations		17,136			15,198			31,392			21,669
Total operating expenses	$	197,646		$	187,065		$	360,363		$	242,003
Operating income (loss)	$	108,448		$	29,308		$	74,048		$	(38,684	)
Other (expense) income:
Interest expense		(37,551	)		(29,835	)		(60,307	)		(31,545	)
(Loss) gain on derivatives, net		(37,649	)		41,141			5,020			(9,153	)
Interest income		2,473			2,111			4,370			3,916
Loss on extinguishment of long-term debt		(4,012	)		—			—			—
Loss on fair value of 11.00% Senior notes due 2023		(27,830	)		—			—			—
Total other (expense) income	$	(104,569	)	$	13,417		$	(50,917	)	$	(36,782	)
Income tax expense		416			11,504			14,095			—
Net income (loss)	$	3,463		$	31,221		$	9,036		$	(75,466	)
Net income (loss) attributable to non-controlling interest	$	338		$	4,767		$	2,581		$	(14,371	)
Net income (loss) attributable to EnVen Energy Corporation	$	3,125		$	26,454		$	6,455		$	(61,095	)
Series A preferred stock dividends		(15,794	)		(8,898	)		(21,590	)		(49	)
Net (loss) income attributable to EnVen Energy Corporation common stockholders	$	(12,669	)	$	17,556		$	(15,135	)	$	(61,144	)

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(In thousands, except for the number of shares outstanding and per share amounts)	Six months ended June 30,						Year ended December 31,
	2018			2017			2017			2016
Historical earnings (loss) per share data(3)
Net (loss) income per common share—basic	$	(0.79	)	$	1.06		$	(0.95	)	$	(4.13	)
Net (loss) income per common share—diluted	$	(0.79	)	$	1.01		$	(0.95	)	$	(4.13	)
Weighted average common shares outstanding—basic		16,131,324			15,865,947			15,912,950			14,795,005
Weighted average common shares outstanding—diluted		16,131,324			25,924,066			15,912,950			14,795,005
Adjusted earnings (loss) per share data(4)
Adjusted net (loss) income per common share—basic
Adjusted net (loss) income per common share—diluted
Adjusted weighted average common shares outstanding—basic
Adjusted weighted average common shares outstanding—diluted
Statement of cash flows data
Net cash provided by operating activities	$	168,799		$	85,371		$	191,482		$	26,954
Net cash used in investing activities	$	(82,805	)	$	(28,527	)	$	(84,759	)	$	(243,631	)
Net cash (used in) provided by financing activities	$	(16,413	)	$	(75,080	)	$	(99,406	)	$	242,633

(In thousands)	As of June 30, 2018		As of December 31, 2017
Balance sheet data
Cash and cash equivalents(6)		91,515		28,848
Accounts receivable		76,183		68,305
Other current assets		40,421		28,373
Total current assets	$	208,119	$	125,526
Property and equipment, net		682,486		691,490
Other non-current assets		133,149		126,025
Total assets	$	1,023,754	$	943,041
Current liabilities		166,348		140,375
Other non-current liabilities		627,983		552,281
Total liabilities	$	794,331	$	692,656
Total equity		229,423		250,385
Total liabilities and equity	$	1,023,754	$	943,041

(1) The total revenues and total operating expenses for the six months ended June 30, 2017 and the years ended December 31, 2017 and 2016 have not been adjusted to reflect the adoption of ASC 606 and include transportation, gathering, and processing costs as a reduction to total revenues and not as a component of operating expense.

(2) As a result of the adoption of ASC 606, we recorded $5.3 million of transportation, gathering, and processing costs for the six months ended June 30, 2018. Prior to the adoption of ASC 606 on January 1, 2018, certain transportation, processing, and gathering costs for our operated properties were presented net in oil, natural gas, and NGL revenues. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 2—Basis of Presentation and Summary of Significant Accounting Policies—Revenue—Adoption of ASC 606” for further discussion of the adoption of ASC 606.

(3) Historical share and per share information does not give effect to the consummation of the Stock Split to be effected immediately prior to the completion of this offering.

(4) As adjusted amounts give effect to the consummation of the Stock Split to be effected immediately prior to the completion of this offering pursuant to which each share of common stock held by the holder of common share will be exchanged into              shares of common stock.

(5) Does not include current portion of restricted cash of approximately $9.4 million and $6.8 million as of June 30, 2018 and December 31, 2017, respectively, reserved as cash collateral for certain bonding requirements and amounts held in escrow for plugging and abandonment obligations.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated Financial Data” and the financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Special Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

We are an independent oil and natural gas company engaged in the development, exploitation, exploration and acquisition of primarily crude oil properties in the deepwater region of the U.S. Gulf of Mexico. We focus on acquiring and developing operated, deepwater assets that we believe have untapped, lower-risk drill bit opportunities and will provide strong cash flow and significant production potential. This strategy allows us to benefit from the favorable geologic and economic characteristics of the deepwater U.S. Gulf of Mexico fields.

Business Environment

Certain trends and general economic or industry-specific factors may affect our financial performance and results of operations in the future, both in the short term and in the long term. Our financial condition and results of operations depend, in part, upon the factors described below.

U.S. Gulf of Mexico. After the lifting of the drilling moratorium in the U.S. Gulf of Mexico in 2011, exploration and production companies resumed their exploration and development activity in the deepwater and ultra-deepwater regions of the U.S. Gulf of Mexico. Many of these companies continue to divest their assets in these deepwater fields, and we believe that as larger operators with different cost structures and priorities seek to focus on larger and more capital-intensive projects in the ultra-deepwater U.S. Gulf of Mexico fields, we will continue to see opportunities to acquire what we view as under-exploited deepwater positions in the U.S. Gulf of Mexico.

We believe that some large operators are motivated to accelerate their divesting of still under-exploited U.S. Gulf of Mexico deepwater assets, amongst others, that may no longer comprise the core of their current strategy, and thus provide us with an opportunity to acquire assets in our areas of focus that we believe will provide risk adjusted attractive returns on our investment. We are proactively pursuing acquisitions of assets that in general (i) have proved developed producing reserves with further development and exploitation potential, particularly assets where our multidisciplinary technical team believes have unbooked hydrocarbon resources, (ii) have oil-weighted production, (iii) have operated assets that allow us to control operating costs, project selection, timing and costs, and the ultimate timing and costs of P&A liabilities, (iv) have accompanying infrastructure for offtake and processing, or which leverage our existing infrastructure, and (v) have the potential to be direct-negotiated transactions. We believe we are favorably positioned in the market to execute on expected future acquisitions as the industry in the U.S. Gulf of Mexico consolidates.

Commodity prices. Oil and natural gas prices are predominantly driven by the physical market, supply and demand, financial markets, and national and international politics. Such prices have fluctuated significantly

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during the past several years due to a combination of factors including increased U.S. supply, global economic concerns, and decisions by OPEC regarding supply.

Oil, natural gas and NGL prices weakened significantly from 2014 to 2016 due to a combination of factors, as discussed above. This trend started to improve in 2017; however, oil and natural gas prices are still lower than recent historical averages and continue to be volatile. As a result, changes in our results of operations between periods may be disproportionately affected by commodity prices and may not accurately reflect changes in our operations.

The NYMEX WTI average price is a widely used benchmark in the pricing of domestic and imported oil in the U.S. NYMEX WTI oil prices reached a high of $74.15 per Bbl and a low of $59.19 per Bbl for the six months ended June 30, 2018 compared to a high of $54.45 per Bbl and a low of $42.53 per Bbl for the six months ended June 30, 2017. NYMEX WTI oil prices reached a high of $60.42 per Bbl and averaged $50.85 per Bbl for the year ended December 31, 2017 compared to a high of $54.06 per Bbl and an average of $43.47 per Bbl for the year ended December 31, 2016.

The NYMEX HH average price of natural gas is a widely used benchmark for the pricing of natural gas in the U.S. NYMEX HH natural gas prices reached a high of $3.63 per MMBtu and a low of $2.55 per MMBtu for the six months ended June 30, 2018 compared to a high of $3.42 per MMBtu and a low of $2.56 per MMBtu for the six months ended June 30, 2017. NYMEX HH natural gas prices reached a high of $3.42 per MMBtu and averaged $3.02 per MMBtu for the year ended December 31, 2017 compared to a high of $3.93 per MMBtu and an average of $2.55 per MMBtu for the year ended December 31, 2016.

Factors Affecting Comparability

Our historical financial condition and results of operations for the periods presented may not be comparable, either between periods or going forward due to the factors described below.

Marathon Acquisitions

On December 18, 2015, we acquired ownership interest in and operatorship of the U.S. Gulf of Mexico Ewing Bank 873/917/963, including the Lobster platform (collectively, “Lobster”), a subsea facility, and 29 wells, and ownership interest in the Vioska Knoll 742/786/830 (“Petronius”) field, including 23 wells, from Marathon for an effective purchase price of $104.6 million. On February 5, 2016, we acquired ownership interest in the U.S. Gulf of Mexico Atwater Valley 574/575/618 (“Neptune”), including the Neptune platform, a subsea facility, and seven wells and an overriding interest in the Ship Shoal 243 lease from Marathon for an effective purchase price of $4.0 million (collectively, the “Marathon Acquisitions”). The Marathon Acquisitions were funded using the net proceeds of a private offering in 2015 of 13,732,925 units, each unit consisting of one share of Class A common stock of Energy Ventures GoM Holdings, LLC, one warrant to purchase 0.07282 shares of Class A Common Stock (not giving effect to the Stock Split) at an exercise price of $12.50 per share and one warrant to purchase 0.07282 shares of Class A (not giving effect to the Stock Split) at an exercise price of $15.00 per share, which resulted in net proceeds of $125.7 million, including underwriting fees and offering expenses of $7.6 million (the “2015 Offering”).

Series A Preferred Stock & Shell Acquisition

On December 30, 2016, our board of directors designated 9,867,930 shares of our authorized and unissued Series A preferred stock with a par value of $0.001 per share. On the same day, we issued 6,159,596 shares of Series A preferred stock to institutional investors for $12.00 per share, resulting in net proceeds of $72.7 million, including initial purchaser discounts and offering expenses of $1.2 million (the “Series A Preferred Stock Offering”). As a result of this offering, all the outstanding shares of the Series A preferred stock will be automatically converted into shares of Class A common stock. See “Capitalization.”

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The net proceeds of the Series A Preferred Stock Offering were used to fund the acquisition (the “Shell Acquisition”) of 100% working interest in the U.S. Gulf of Mexico Green Canyon 158 and 202 (“Brutus”) and 248 (“Glider”) fields, including the Brutus tension-leg platform, a subsea facility, 16 wells and two transportation pipelines from Shell. See “Statements of Revenues and Direct Operating Expenses” of Brutus and Glider Properties included elsewhere in this prospectus for the revenues and direct operating expenses related to these properties. The total adjusted consideration of $238.7 million included an initial purchase price of $375.0 million and purchase price adjustments from the contractual effective date of the acquisition, January 1, 2016, through the acquisition date of $136.3 million. A portion of the Shell Acquisition was funded with the cash proceeds from the Series A Preferred Stock Offering, additional borrowings on our Revolving Credit Facility, and the exercise of an accordion feature of our Second Lien Term Loan. Additionally, $44.5 million of the purchase price consideration was provided by issuing 3,708,334 shares of our Series A preferred stock to Shell, with an issuance price of $12.00 per share on the date of acquisition.

In March 2018, we repurchased 2,149,217 shares of our Series A Preferred Stock from Shell at $12.00 per share, for a total price of $25.8 million. Additionally, certain of our equity investors repurchased the remaining 2,229,812 shares (including the paid-in-kind dividends issued on March 31, 2018) at $12.00 per share. As a result of this repurchase, Shell no longer owns any of our Series A Preferred Stock.

Revenue Recognition—Adoption of ASC 606

On January 1, 2018, we adopted ASC 606, which requires certain costs related to transportation, gathering, and processing to be separately presented as a component of operating expense in the condensed consolidated statement of operations for the six months ended June 30, 2018 included elsewhere in the prospectus. Prior to the adoption of ASC 606, the majority of these costs were accounted for as a deduction to oil, natural gas, and NGL revenue and included within total revenues on the consolidated statement of operations. As a result, $5.3 million of transportation, gathering, and processing costs are presented as a component of operating expense and not as a reduction of oil, natural gas, and NGL revenue for the six months ended June 30, 2018. We have elected to adopt ASC 606 using the modified retrospective approach, and as such, prior period amounts for the six months ended June 30, 2017 and the fiscal years ended December 31, 2017 and 2016 have not been restated. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 2—Basis of Presentation and Summary of Significant Accounting Policies—Revenue—Adoption of ASC 606” for a further discussion regarding the impact of adopting ASC 606.

2018 Refinancing Transactions

In February 2018, we completed a private offering of $325.0 million aggregate principal amount of the 2023 Notes, resulting in net proceeds of $317.0 million, after deducting initial purchaser fees and offering expenses of $8.0 million (the “2023 Notes Offering”). We used the net proceeds of the 2023 Notes Offering to repay all of the outstanding indebtedness under our Revolving Credit Facility and our Second Lien Term Loan. Additionally, at that time, we made certain amendments to the Revolving Credit Facility and terminated the Second Lien Term Loan (such actions, together with the 2023 Notes Offering, the “2018 Refinancing Transactions”). See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 2—Basis of Presentation and Summary of Significant Accounting Policies—Debt Issuance Costs” for a discussion of the 2018 Refinancing Transactions costs and “Notes to Unaudited Condensed Consolidated Financial Statements—Note 8—Long-term Debt” for further discussion of the 2018 Refinancing Transactions.

Post-Offering Expenses

As a public company, we will be implementing additional procedures and processes for the purpose of addressing the standards and requirements applicable to public companies. We expect to incur additional annual expenses related to these steps and, among other things, additional directors’ and officers’ liability insurance, director fees, reporting requirements of the SEC, transfer agent fees, hiring additional personnel, increased

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auditing and legal fees and similar expenses. We also expect to recognize certain non-recurring costs as part of our transition to a publicly-traded company, consisting of professional fees and other expenses.

In connection with the consummation of this offering, we expect to issue              equity incentive awards to certain employees, including              awards to our executive officers, which we expect to result in $             million of stock-based compensation expense, which we expect to recognize in                     .

Known Trends and Uncertainties

Realized Prices on the Sale of Oil, Natural Gas, and NGLs

Market price components substantially drive our oil, natural gas and NGL revenues, which fluctuate in response to factors that are outside of our control. The majority of our oil production is sold under netback arrangements, in which we sell oil at the wellhead or pipeline interconnect and collect a price, net of any transportation and gathering costs incurred by the purchaser; therefore, the majority of our oil revenues are recorded at the net price received from the purchaser.

Our oil production price has a premium or deduct differential to the prevailing NYMEX WTI price. A substantial portion of our crude differential reflects adjustments for location, crude quality and transportation and gathering costs. Crude location and quality differentials result from contracts that contain a grade differential and/or provisions for quality bank adjustments. Grade differentials consider the crude quality of the oil and its marketability to different marketplaces. Oil contracts may include adjustments for different grade differentials depending on the corresponding production location and crude quality. In addition, the majority of our oil fields have premium or deduct quality bank adjustments for the density of the oil, as characterized by its American Petroleum Institute gravity, and the presence and concentration of impurities, such as sulfur.

During the six months ended June 30, 2018 and the year ended December 31, 2017, our oil produced offshore in the U.S. Gulf of Mexico largely priced using Poseidon and Mars grade differentials. Poseidon and Mars differentials experience volatility, do not always have a linear relationship with each other or with WTI, and may be a premium or deduct to WTI. During the six months ended June 30, 2018 and the year ended December 31, 2017, the majority of our oil recognized favorable grade differential variances compared to the same periods in the prior year. The average monthly differentials of WTI versus Poseidon and WTI versus Mars were an approximate premium of $0.06 per Bbl and $0.48 per Bbl, respectively, for the six months ended June 30, 2018 compared to an approximate deduct of $1.91 per Bbl and $1.66 per Bbl, respectively, for the six months ended June 30, 2017. The average monthly differentials of WTI versus Poseidon and WTI versus Mars for the year ended December 31, 2017 were an approximate deduct of $0.41 per Bbl and $0.15 per Bbl, respectively, compared to an approximate deduct of $3.61 per Bbl and $3.22 per Bbl, respectively, for the year ended December 31, 2016.

The majority of our natural gas production is delivered to a natural gas processor who gathers and processes our raw natural gas and remits proceeds for the resulting sales of NGLs and residue gas. NGL sales occur at the tailgate of the facility with prices derived from the Mont Belvieu Trading Hub. Generally, we transfer control for natural gas and NGLs at a specified point after processing. Therefore, with the adoption of ASC 606 on January 1, 2018, the costs to transport, gather, compress, and process the natural gas and NGLs, until the time control transfers post-processing, are recorded as a component of operating expense in the condensed consolidated statement of operations for the six months ended June 30, 2018 included elsewhere in this prospectus.

Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity, and supply and demand relationships in that region or locality. Similar to oil, our natural gas production price has a premium or deduct differential to the prevailing NYMEX HH price primarily due to differential adjustments for location and quality and energy content of the natural gas. Location differentials

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result from variances in natural gas transportation costs based on the proximity of the natural gas to its major consuming markets that correspond with the ultimate delivery point as well as individual supply and demand dynamics.

The following table presents the NYMEX WTI and NYMEX HH average prices, our average realized oil and natural gas prices (excluding and including effects of derivatives), our average realized oil and natural gas price differentials (excluding effects of derivatives) to the benchmark prices, and our average realized NGL prices for the periods indicated:

	Six months ended June 30,						Year ended December 31,
	2018			2017(1)			2017(1)			2016(1)
Oil (per Bbl):
NYMEX WTI Average	$	65.46		$	49.95		$	50.85		$	43.47
Average realized price (excluding effects of derivatives)(2)	$	65.19		$	46.30		$	48.66		$	37.18
Average realized price differential to benchmark(3)	$	(0.27	)	$	(3.65	)	$	(2.19	)	$	(6.29	)
Percentage of average realized price to benchmark(3)		99.6	%		92.7	%		95.7	%		85.5	%
Average realized price (including effects of derivatives)(2)(4)	$	61.86		$	50.06		$	50.67		$	37.68
Natural gas:
NYMEX HH Average ($/MMBtu)	$	2.84		$	3.10		$	3.02		$	2.55
Average realized price (excluding effects of derivatives) ($/Mcf)	$	3.64		$	2.92		$	2.93		$	2.12
Average realized price differential to benchmark ($/Mcf)(3)(5)	$	0.69		$	(0.29	)	$	(0.20	)	$	(0.52	)
Percentage of average realized price to benchmark(3)(5)		123.6	%		90.8	%		93.6	%		80.3	%
Average realized price (including effects of derivatives) ($/Mcf)(4)	$	3.66		$	3.04		$	3.15		$	2.18
NGLs (per Bbl):
Average realized price	$	28.94		$	16.75		$	18.22		$	13.31

(1) The average realized prices (excluding and including effects of derivatives) for the six months ended June 30, 2017 and the years ended December 31, 2017 and 2016 have not been adjusted to reflect the adoption of ASC 606 and include transportation, gathering, and processing costs as a reduction to oil, natural gas and NGL revenues.

(2) For the six months ended June 30, 2018, a portion of our oil production was sold under netback arrangements and therefore certain oil revenues have been recorded at the net price received from the purchaser regardless of the adoption of ASC 606.

(3) Benchmarks are the NYMEX WTI and NYMEX HH average prices for oil and natural gas, respectively.

(4) The effects of derivatives represents, as applicable to the periods presented: (i) current period derivative settlements; (ii) the exclusion of the impact of current period settlements for early-terminated derivatives originally designated to settle against future production period revenues; (iii) the exclusion of option premiums paid in current periods related to future production period revenues; (iv) the impact of the prior period settlements of early-terminated derivatives originally designated to settle against future production period revenues; and (v) the impact of option premiums paid in prior periods related to current period production revenues.

(5) Calculated using a conversion factor of one Mcf equal to 1.037 MMBtu.

Our average realized oil price (excluding effects of derivatives) for the six months ended June 30, 2018 was $65.19 per Bbl compared to the NYMEX WTI average price of $65.46 per Bbl. Our average realized oil price (excluding effects of derivatives) for the six months ended June 30, 2017 was $46.30 per Bbl compared to the NYMEX WTI average price of $49.95 per Bbl. The 40.8% increase in our average realized oil price was largely due to a 31.1% increase in the NYMEX WTI average price. Additionally, we realized a more favorable realized price differential to benchmark of $(0.27) per Bbl for the six months ended June 30, 2018 compared to $(3.65) per Bbl for the same period of 2017 primarily due to more favorable grade differentials on our corresponding Poseidon and Mars oil volumes of $1.97 per Bbl and $2.14 per Bbl, respectively, compared to the same period of 2017.

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Additionally, our average realized oil price increased by $0.37 per Bbl during the six months ended June 30, 2018 due to the adoption of ASC 606, which resulted in $1.5 million of transportation and gathering costs that are now presented as a component of operating expenses and not as a reduction to oil revenue.

Our average realized oil price (excluding effects of derivatives) for the year ended December 31, 2017 was $48.66 per Bbl compared to the NYMEX WTI average price of $50.85 per Bbl. Our average realized oil price (excluding effects of derivatives) for the year ended December 31, 2016 was $37.18 per Bbl compared to the NYMEX WTI average price of $43.47 per Bbl. The 30.9% increase in our average realized oil price was largely due to a 17.0% increase in the NYMEX WTI average price. The remaining 13.9% increase was due to a more favorable realized price differential to benchmark of $(2.19) per Bbl for the year ended December 31, 2017 compared to $(6.29) per Bbl for the year ended December 31, 2016. The more favorable realized price differential was primarily due to the impact of the grade differentials per Bbl on our corresponding Poseidon and Mars oil volumes. The average monthly differentials of WTI versus Poseidon and WTI versus Mars for the year ended December 31, 2017 was more favorable by $3.20 per Bbl and $3.07 per Bbl, respectively, compared to the year ended December 31, 2016. In addition to the more favorable grade differential on our oil production volumes, the incremental volumes from the Shell Acquisition increased our oil production volumes at a disproportionately favorable pricing mechanism for the year ended December 31, 2017 compared to the year ended December 31, 2016. The incremental Shell Acquisition production contained disproportionately positive oil quality bank adjustments for the year ended December 31, 2017 compared to the year ended December 31, 2016. The combination of the grade differentials and the Shell Acquisition realized pricing drove the overall favorable realized price differential variance for the year ended December 31, 2017 compared to the year ended December 31, 2016.

Our average realized natural gas price (excluding effects of derivatives) for the six months ended June 30, 2018 was $3.64 per Mcf compared to the NYMEX HH average price of $2.84 per MMBtu. Our average realized natural gas price (excluding effects of derivatives) for the six months ended June 30, 2017 was $2.92 per Mcf compared to the NYMEX HH average price of $3.10 per MMBtu. The 24.7% increase in our average realized natural gas price was largely due to a more favorable realized price differential to benchmark of $0.69 per Mcf for the six months ended June 30, 2018 compared to $(0.29) per Mcf for the same period of 2017. Additionally, our average realized natural gas price increased by $0.43 per Mcf during the six months ended June 30, 2018 due to the adoption of ASC 606, which resulted in $2.7 million of transportation and gathering costs that are now presented as a component of operating expenses and not as a reduction to natural gas revenue. These increases were partially offset by an 8.4% decrease in the NYMEX HH average price.

Our average realized natural gas price (excluding effects of derivatives) for the year ended December 31, 2017 was $2.93 per Mcf compared to the NYMEX HH average price of $3.02 per MMBtu. Our average realized natural gas price (excluding effects of derivatives) for the year ended December 31, 2016 was $2.12 per Mcf compared to the NYMEX HH average price of $2.55 per MMBtu. The 38.2% increase in our average realized natural gas price was largely due to an 18.4% increase in the NYMEX HH average price. The remaining 19.8% increase was due to a more favorable realized price differential to benchmark of $(0.20) per Mcf for the year ended December 31, 2017 compared to $(0.52) per Mcf for the year ended December 31, 2016, driven by the Shell Acquisition, which added natural gas production volumes at a disproportionately more favorable pricing mechanism for the year ended December 31, 2017 when compared to the year ended December 31, 2016.

Our average realized NGL price for the six months ended June 30, 2018 was $28.94 per Bbl compared to $16.75 per Bbl for the six months ended June 30, 2017. The 72.8% increase in our average realized NGL price was partially driven by the adoption of ASC 606, which resulted in an increase of $6.92 per Bbl due to processing costs of $0.9 million which are now presented as a component of operating expenses and not as a reduction to NGL revenue. Additionally, the increase in our average realized NGL price was also driven by a 12.6% and 29.0% increase in Mount Belvieu ethane and propane, respectively, monthly settle averages for the six months ended June 30, 2018 compared to the same period of 2017.

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Our average realized NGL price for the year ended December 31, 2017 was $18.22 per Bbl compared to $13.31 per Bbl for the year ended December 31, 2016. The 36.9% increase in our average realized NGL price was primarily due to more favorable ethane, propane, and butane realized prices for the year ended December 31, 2017 compared to the year ended December 31, 2016. During the year ended December 31, 2017, the Mount Belvieu ethane monthly settle average increased 25.8% compared to the year ended December 31, 2016.

See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 2—Basis of Presentation and Summary of Significant Accounting Policies—Revenue—Adoption of ASC 606” for further discussion of the adoption of ASC 606.

Commodity Derivatives

Oil, natural gas and NGL prices are the most significant factors impacting our results of operations and continued price variations can have a material impact on our financial results and capital expenditures. To reduce our price volatility, we may enter into derivative contracts to economically hedge a significant portion of our estimated production from our proved developed producing oil and natural gas properties against adverse fluctuations in commodity prices. By doing so, we believe we can mitigate, but not eliminate, the potential negative effects of decreases in oil and natural gas prices on our cash flows from operations. However, our hedging activity could reduce our ability to benefit from increases in oil and natural gas prices. We could sustain losses to the extent our derivative contract prices are lower than market prices and, conversely, we could recognize gains to the extent our derivative contract prices are higher than market prices.

Our oil and natural gas derivative instruments consist of various instruments, including financially settled oil and natural gas call options, put options, and swaps (including basis swaps), or combinations of these arrangements, which are described below.

• Swaps: We receive a fixed price and pay a variable market price to the counterparty for contracted commodity volumes over specified time periods. Basis swaps allow us to receive a fixed price differential based on the Argus WTI Cushing index price and pay a variable price differential to the counterparty based on the Argus Mars index price for contracted oil volumes over a specified time period.

• Sold Call Options: A sold call option gives the counterparty the right, but not the obligation, to purchase the underlying commodity volumes from us at a specified price (“strike/ceiling price”) over a specified time period. At settlement, if the market price is above the fixed ceiling price of the sold call option, we pay the counterparty the difference. If the market price settles below the fixed ceiling price of the sold call option, no payment is due from either party.

• Purchased Put Options: A purchased put option gives us the right, but not the obligation, to sell the underlying commodity volumes to the counterparty at a specified price (“strike/floor price”) over a specified time period. At settlement, if the market price is below the fixed floor price of the purchased put option, the counterparty pays us the difference. If the market price settles above the fixed floor price of the purchased put option, no payment is due from either party.

• Put Spreads: A put spread is a combination of a sold put option and a purchased put option. At settlement, if the market price is below the sold put option strike price, we receive the difference between the two strike prices from the counterparty. If the market price settles below the purchased put option strike price but above the sold put option strike price, we receive the difference between the purchased put option strike price and the market price from the counterparty. If the market price settles above the purchased put option strike price, no payment is due from either party.

• Collars: A collar contains a purchased put option (“fixed floor price”) and a sold call option (“fixed ceiling price”). At settlement, if the market price is below the fixed floor price, we receive the difference between the fixed floor price and the market price from the counterparty. If the market price settles above the fixed ceiling price, we pay the counterparty the difference between the market price and the fixed ceiling price.

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• Three-way Collars: A three-way collar combines a sold call option (“fixed ceiling price”), a purchased put option (“fixed floor price”), and a sold put option (“fixed subfloor price”). At settlement, if the market price is between the fixed floor price and the fixed subfloor price or is above the fixed ceiling price, we receive the fixed floor price from the counterparty or pay the counterparty the market price, respectively. If the market price settles below the fixed subfloor price, we receive the market price plus the difference between the fixed floor price and the fixed subfloor price from the counterparty. If the market price settles between the fixed floor price and fixed ceiling price, no payments are due from either party.

See “—Realized Prices on the Sale of Oil, Natural Gas, and NGLs” above for a discussion of our realized prices excluding and including effects of derivatives and “—Results of Operations—Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017—Other Expenses” and “—Results of Operations—Year Ended December 31, 2017 Compared to Year Ended December 31, 2016—Other Expenses” below for a discussion of our recognized gains or losses on derivative contracts. See “—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” for a discussion of our hedging requirements per our Revolving Credit Facility agreement.

Our oil derivative contracts, other than our oil basis swaps, are indexed to the NYMEX WTI. Our oil basis swaps are settled based on the differential between the Argus WTI Cushing index price and the Argus Mars index price. Our natural gas derivative contracts are indexed to NYMEX HH.

We had the following outstanding oil and natural gas derivative contracts in place as of June 30, 2018:

	Remainder of 2018		2019
Oil Swaps:
Notional volume (Bbl)		728,040		763,563
Weighted average price ($/Bbl)	$	53.15	$	50.70
Oil Sold Calls:
Notional volume (Bbl)		184,000		—
Weighted average ceiling price ($/Bbl)	$	75.00	$	—
Oil Purchased Puts:
Notional volume (Bbl)		307,317		1,616,001
Weighted average ceiling price ($/Bbl)	$	50.00	$	52.92
Oil Collars:
Notional volume (Bbl)		1,663,040		682,500
Weighted average floor price ($/Bbl)	$	49.59	$	52.00
Weighted average ceiling price ($/Bbl)	$	64.27	$	70.00
Oil Three-way Collars:
Notional volume (Bbl)		301,006		—
Weighted average sub-floor price ($/Bbl)	$	40.00	$	—
Weighted average floor price ($/Bbl)	$	50.00	$	—
Weighted average ceiling price ($/Bbl)	$	65.04	$	—
Oil Put Spreads:
Notional volume (Bbl)		—		268,806
Weighted average sub-floor price ($/Bbl)	$	—	$	45.00
Weighted average floor price ($/Bbl)	$	—	$	55.00
Oil Basis Swaps:
Notional volume (Bbl)		612,000		—
Weighted average price ($/Bbl)	$	4.61	$	—
Natural Gas Purchased Puts:
Notional volume (MMBtu)		1,758,129		906,861
Weighted average price ($/MMBtu)	$	2.75	$	2.75

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	Remainder of 2018		2019
Natural Gas Swaps:
Notional volume (MMBtu)		833,135		2,591,700
Weighted average price ($/MMBtu)	$	3.01	$	2.75
Natural Gas Collars:
Notional volume (MMBtu)		—		680,139
Weighted average floor price ($/MMBtu)	$	—	$	3.00
Weighted average ceiling price ($/MMBtu)	$	—	$	3.50

We had the following outstanding oil and natural gas derivative contracts in place as of December 31, 2017:

	2018		2019
Oil Purchased Puts:
Notional volume (Bbl)		958,047		135,000
Weighted average price ($/Bbl)	$	49.53	$	45.00
Oil Swaps:
Notional volume (Bbl)		1,433,890		763,563
Weighted average price ($/Bbl)	$	53.14	$	50.70
Oil Collars:
Notional volume (Bbl)		1,925,636		—
Weighted average floor price ($/Bbl)	$	45.00	$	—
Weighted average ceiling price ($/Bbl)	$	62.91	$	—
Oil Three-way Collars:
Notional volume (Bbl)		857,013		—
Weighted average sub-floor price ($/Bbl)	$	40.00	$	—
Weighted average floor price ($/Bbl)	$	50.00	$	—
Weighted average ceiling price ($/Bbl)	$	65.08	$	—
Oil Put Spreads:
Notional volume (Bbl)		—		398,001
Weighted average sub-floor price ($/Bbl)	$	—	$	40.00
Weighted average floor price ($/Bbl)	$	—	$	50.00
Natural Gas Purchased Puts:
Notional volume (MMBtu)		3,747,255		906,861
Weighted average price ($/MMBtu)	$	2.75	$	2.75
Natural Gas Swaps:
Notional volume (MMBtu)		2,829,797		2,591,700
Weighted average price ($/MMBtu)	$	3.21	$	2.75
Natural Gas Collars:
Notional volume (MMBtu)		—		680,139
Weighted average floor price ($/MMBtu)	$	—	$	3.00
Weighted average ceiling price ($/MMBtu)	$	—	$	3.50
Natural Gas Three-way Collars:
Notional volume (MMBtu)		216,678		—
Weighted average sub-floor price ($/MMBtu)	$	2.75	$	—
Weighted average floor price ($/MMBtu)	$	3.50	$	—
Weighted average ceiling price ($/MMBtu)	$	3.91	$	—

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We had the following outstanding oil and natural gas derivative contracts in place as of December 31, 2016:

	2017		2018
Oil Swaps:
Notional volume (Bbl)		536,902		366,240
Weighted average price ($/Bbl)	$	55.00	$	56.27
Oil Three-way Collars:
Notional volume (Bbl)		2,691,842		662,013
Weighted average sub-floor price ($/Bbl)	$	44.58	$	40.00
Weighted average floor price ($/Bbl)	$	50.00	$	50.00
Weighted average ceiling price ($/Bbl)	$	63.64	$	65.10
Oil Collars:
Notional volume (Bbl)		—		1,460,000
Weighted average floor price ($/Bbl)	$	—	$	45.00
Weighted average ceiling price ($/Bbl)	$	—	$	65.05
Natural Gas Swaps:
Notional volume (MMBtu)		3,203,599		1,285,958
Weighted average price ($/MMBtu)	$	3.19	$	3.71
Natural Gas Collars:
Notional volume (MMBtu)		517,476		—
Weighted average floor price ($/MMBtu)	$	3.00	$	—
Weighted average ceiling price ($/MMBtu)	$	3.35	$	—
Natural Gas Sold Calls:
Notional volume (MMBtu)		2,177,087		—
Weighted average ceiling price ($/MMBtu)	$	3.61	$	—

Oil and Natural Gas Properties Full Cost Ceiling Test

Under the full cost method of accounting, we perform the full cost ceiling test at the end of each reporting period. Per the full cost ceiling test, net capitalized costs less deferred income taxes are limited to the present value of estimated future net cash flows from proved oil and natural gas reserves computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unevaluated properties and excluding cash flows related to estimated abandonment costs associated with developed properties (the “ceiling limitation”). If the net capitalized costs exceed the ceiling limitation, we recognize an impairment equal to the excess of the net capitalized costs over the ceiling limitation. We did not recognize any impairments of oil and natural gas properties during the three and six months ended June 30, 2018 and 2017.

Production Volumes

As reservoirs deplete, production from a given well or formation decreases; as a result, growth in our future production and reserves will depend on our ability to continue to add proved oil, natural gas, and NGL reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through efficiently developing or working over our existing and acquired assets. Our ability to add reserves through acquisitions is dependent on many factors, including our ability to successfully identify and consummate acquisitions (including obtaining regulatory approvals) and raise capital to finance such acquisitions.

Income Taxes

On December 22, 2017, the U.S. Congress enacted the Tax Act. The Tax Act significantly changes U.S. corporate income tax laws beginning, generally, in 2018. These changes include, among others, (i) a reduction of the U.S. corporate income tax rate from a top marginal rate of 35% to a flat rate of 21%, (ii) elimination of the

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corporate alternative minimum tax, (iii) immediate deductions for certain capital expenditures rather than deductions for depreciation expense over time, (iv) limitation on the tax deduction for interest expense to 30% of adjusted taxable income, (v) limitation of the deduction for net operating losses to 80% of current year taxable income and elimination of net operating loss carrybacks, and (vi) elimination of many business deductions and credits, including the domestic production activities deduction and the deduction for entertainment expenditures. We do not expect the provisions of the Tax Act to have a material adverse impact on our future effective tax rate, after-tax earnings or cash flows.

As a result of the Tax Act, we remeasured our deferred tax assets and liabilities using the new corporate income tax rate, which did not impact our income tax provision or the amounts recorded on the accompanying audited consolidated balance sheets due to the offsetting effect of adjusting the valuation allowance. Due to various estimates included in determining the tax provision, the remeasurement is considered provisional and may be adjusted through subsequent events such as the filing of our consolidated federal income tax return for the year ended December 31, 2017.

During the six months ended June 30, 2018, we recognized income tax expense of $0.4 million, resulting in an effective tax rate of 10.7%. During the year ended December 31, 2017, we recognized income tax expense of $14.1 million, resulting in an effective tax rate of 60.9%.

Sources of Our Revenues

The majority of our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. A large portion of our oil production is sold under netback arrangements, in which we sell oil at the wellhead or pipeline interconnect and collect a price, net of any transportation and gathering costs incurred by the purchaser. Therefore, the majority of our oil revenues are recorded at the net price received from the purchaser. The majority of our natural gas production is delivered to a natural gas processor who gathers and processes our raw natural gas and remits proceeds for the resulting sales of NGLs and residue gas, which occur at the tailgate of the facility with prices derived from the Mont Belvieu Trading Hub. Generally, we transfer control for natural gas and NGLs at a specified point after processing. With the adoption of ASC 606 on January 1, 2018, the costs to transport, gather, compress, and process the natural gas and NGLs, until the time control transfers post-processing, are recorded as a component of operating expense. See our unaudited condensed consolidated statement of operations for the six months ended June 30, 2018 included elsewhere in this prospectus.

Additionally, we generate revenue from third-party production handling agreements, where we receive a fee for processing third-party production at our facilities. We also receive revenue from third parties for the use of our pipelines. The majority of our third-party production handling agreements and pipeline revenue contracts were acquired in the Shell Acquisition and Marathon Acquisitions. Our oil, natural gas, and NGL revenues do not include the effects of derivatives and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Principal Components of Our Cost Structure

Lease operating expenses. LOE are the day-to-day operating costs incurred to produce our oil, natural gas and NGLs. Such costs generally consist of direct labor, utilities, materials and supplies and do not include G&A expenses or production and severance taxes. Certain items, such as direct labor, materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. Certain LOE are variable and increase or decrease as the level of produced hydrocarbons increases or decreases.

Workover, repair, and maintenance expenses. Workover, repair, and maintenance expenses are incurred during the ordinary course of operations and in connection with the improvement of assets we have acquired.

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Workovers, repairs, and maintenance activities may be complex to execute and therefore can be expensive to complete, but constitute an important aspect of our business strategy aimed at increasing production efficiency with respect to the assets we acquire. In many cases, “through-tubing” workover operations are conducted to complete treatments or service activities aimed at improving well performance to avoid more extensive and expensive servicing. A full workover is more expensive and involves activities requiring the temporary removal of production tubing string after drilling has been complete.

Depreciation, depletion, and amortization. We follow the full cost method of accounting for oil and natural gas activities and capitalize all costs associated with the acquisition, exploration and development of oil and natural gas properties. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals, costs of drilling, completing and equipping successful and unsuccessful oil and natural gas wells and directly related costs.

Certain oil and natural gas property costs represent investments in unproved properties and are excluded from costs being depleted. These costs include nonproducing leasehold, geological and geophysical costs associated with unproved acreage and exploration drilling costs. Unproved properties and exploratory costs are excluded from the depreciable base until management determines the existence of proved oil and natural gas reserves on the respective property or the costs are impaired. We review unproved properties to determine if the costs should be reclassified and included as a part of the depreciable base at least quarterly.

The capitalized costs of proved oil and natural gas properties, net of accumulated DD&A plus estimated future development costs related to proved oil and natural gas reserves and estimated future P&A costs are amortized on a unit of production method over the estimated productive life of the proved reserves to determine DD&A for each period.

General and administrative expenses. G&A expenses consist of overhead, including salaries, incentive compensation, benefits for our corporate staff, costs of maintaining our headquarters and costs of managing our production and development operations. G&A expenses also include software fees and audit, legal compliance and other professional service fees.

We capitalize a portion of our salaries, wages, and benefits to the extent that they are directly allocable to capital exploration and development activity. In addition, we record certain of these costs as LOE when they are directly attributable to maintaining the oil, natural gas, and NGL production of our operated oil and natural gas properties. For oil and natural gas properties for which we are the operator, we receive reimbursement for a portion of these costs and allowable overhead from other working interest owners during the drilling and production phases of the property.

Interest expense. We finance a portion of our working capital requirements and capital expenditures with borrowings under our credit facilities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect this interest in the Interest expense line item in our consolidated statements of operations included elsewhere in this prospectus.

In addition, the BOEM and certain third parties require that we post supplemental and performance bonds for our decommissioning obligations. We enter into arrangements with surety companies who provide these bonds on our behalf, and we usually pay an annual premium in exchange for the surety’s financial strength to extend credit. The surety bond premium is amortized over the life of the surety bond in the Interest expense line item in our consolidated statements of operations included elsewhere in this prospectus.

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Results of Operations

The following table presents selected financial and operating information for the periods indicated:

	Six months ended June 30,						Year ended December 31,
	2018			2017			2017			2016
	(In thousands, except production and average sales prices)
Selected financial data:
Total revenues(1)	$	306,094		$	216,373		$	434,411		$	203,319
Total operating expenses(1)		197,646			187,065			360,363			242,003
Operating income		108,448			29,308			74,048			(38,684	)
Total other (expense) income		(104,569	)		13,417			(50,917	)		(36,782	)
Income before income taxes		3,879			42,725			23,131			(75,466	)
Income tax expense		416			11,504			14,095			—
Net income (loss)		3,463			31,221			9,036			(75,466	)
Net income (loss) attributable to non-controlling interest		338			4,767			2,581			(14,371	)
Net income (loss) attributable to EnVen Energy Corporation		3,125			26,454			6,455			(61,095	)
Series A preferred stock dividends		(15,794	)		(8,898	)		(21,590	)		(49	)
Net (loss) income attributable to EnVen Energy Corporation common stockholders	$	(12,669	)	$	17,556		$	(15,135	)	$	(61,144	)
Production:
Oil (MBbls)		4,173			4,086			7,865			4,636
Natural gas (MMcf)		6,198			5,502			10,316			9,243
NGLs (MBbls)		127			145			301			279
Total production (MBoe)		5,333			5,147			9,885			6,455
Average sales prices:(2)
Oil (per Bbl)	$	65.19		$	46.30		$	48.66		$	37.18
Natural gas (per Mcf)	$	3.64		$	2.92		$	2.93		$	2.12
NGLs (per Bbl)	$	28.94		$	16.75		$	18.22		$	13.31
Average price (per Boe)	$	55.93		$	40.35		$	42.33		$	30.32

(1) The total revenues and total operating expenses for the six months ended June 30, 2017 and the years ended December 31, 2017 and 2016 have not been adjusted to reflect the adoption of ASC 606 and include transportation, gathering, and processing costs as a reduction to total revenues and not as a component of operating expense.

(2) Excluding effects of derivatives.

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Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017

Production

The following table presents our production by product for the periods indicated:

	Six months ended June 30,
	2018					2017
	Volume		% of Total			Volume		% of Total			Change			% Change
Production:
Oil (MBbls)		4,173		78.2	%		4,086		79.4	%		87			2.1	%
Natural gas (MMcf)		6,198		19.4	%		5,502		17.8	%		696			12.6	%
NGLs (MBbls)		127		2.4	%		145		2.8	%		(18	)		(12.4	)%
Total production (MBoe)		5,333		100.0	%		5,147		100.0	%		186			3.6	%
Average daily production:
Oil (MBbls/d)		23.1		78.2	%		22.6		79.4	%		0.5
Natural gas (MMcf/d)		34.2		19.4	%		30.4		17.8	%		3.8
NGLs (MBbls/d)		0.7		2.4	%		0.8		2.8	%		(0.1	)
Total production (MBoe/d)		29.5		100.0	%		28.4		100.0	%		1.1

For the six months ended June 30, 2018, oil production increased by 87 MBbls, or 2.1%, natural gas production increased by 696 MMcf, or 12.6%, NGL production decreased by 18 MBbls, or 12.4%, and total production increased by 186 MBoe, or 3.6%, compared to the six months ended June 30, 2017. During the six months ended June 30, 2018, production volumes from our Brutus and Lobster fields increased as a result of our multi-project capital programs at those fields. These increases were partially offset by the natural production decline associated with our oil and natural gas properties and a brief, non-recurring shut-in of the third party natural gas pipeline servicing our Brutus and Glider fields, which was resolved in the first quarter of 2018. Additionally, during the transition to a new gas purchaser at one of our fields, we were not allocated any NGL volumes from the field for two months of the second quarter of 2018, resulting in lower NGL production volumes for the six months ended June 30, 2018 compared to the same period of 2017. To compensate for the error, we received a premium to the price for the natural gas volumes sold to the new purchaser for the two impacted months.

Revenue

The following table presents the components of our revenue, production, and average sales prices for the periods indicated:

	Six months ended June 30,
	2018		2017(1)		Change			% Change
	(In thousands, except production, average sales prices and percentages)
Oil revenue	$	272,056	$	189,175	$	82,881			43.8	%
Natural gas revenue		22,547		16,080		6,467			40.2	%
NGL revenue		3,675		2,429		1,246			51.3	%
Production handling and other income		7,816		8,689		(873	)		(10.0	)%
Total revenues	$	306,094	$	216,373	$	89,721			41.5	%
Production:
Oil (MBbls)		4,173		4,086		87			2.1	%
Natural gas (MMcf)		6,198		5,502		696			12.6	%
NGLs (MBbls)		127		145		(18	)		(12.4	)%
Total production (MBoe)		5,333		5,147		186			3.6	%

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	Six months ended June 30,
	2018		2017(1)		Change		% Change
	(In thousands, except production, average sales prices and percentages)
Average sales prices:(2)
Oil (per Bbl)	$	65.19	$	46.30	$	18.89		40.8	%
Natural gas (per Mcf)	$	3.64	$	2.92	$	0.72		24.7	%
NGLs (per Bbl)	$	28.94	$	16.75	$	12.19		72.8	%
Average price (per Boe)	$	55.93	$	40.35	$	15.58		38.6	%

(1) The oil, natural gas and NGL revenues for the six months ended June 30, 2017 have not been adjusted to reflect the adoption of ASC 606, per the modified retrospective approach, and include transportation, gathering, and processing costs as a reduction to oil, natural gas, and NGL revenues.

(2) Excluding effects of derivatives.

Oil revenue. For the six months ended June 30, 2018, oil revenues were $272.1 million compared to $189.2 million for the six months ended June 30, 2017. The increase of 43.8% was primarily driven by a 40.8% increase in our average realized oil price primarily due to higher commodity prices during the six months ended June 30, 2018 compared to the same period of 2017. Additionally, as a result of the adoption of ASC 606, our oil revenue for the six months ended June 30, 2018 excludes certain transportation and gathering costs resulting in an increase of $1.5 million in total oil revenue and an increase of $0.37 per Bbl in our average realized oil price. Additionally, as a result of the capital programs at our Brutus and Lobster fields, our oil production volumes from those fields increased for the six months ended June 30, 2018 compared to the same period of 2017, partially offset by the natural production decline associated with our other oil properties and a brief, non-recurring shut-in of the third party natural gas pipeline servicing our Brutus and Glider fields, which was resolved in the first quarter of 2018.

Natural gas revenue. For the six months ended June 30, 2018, natural gas revenues were $22.5 million compared to $16.1 million for the six months ended June 30, 2017. The increase of 40.2% was partially driven by a 24.7% increase in our average realized natural gas price primarily due to the adoption of ASC 606, which resulted in a $2.7 million increase in our natural gas price and a $0.43 per Mcf increase in our average realized natural gas price primarily due to the exclusion of certain transportation, gathering, and processing costs from our natural gas revenues for the six months ended June 30, 2018. Additionally, our natural gas production volumes increased 12.6% primarily due to increased natural gas volumes from our Brutus and Lobster fields as a result of our capital programs at those fields. This increase was partially offset with a brief, non-recurring shut-in of the third party natural gas pipeline servicing our Brutus and Glider fields, which was resolved in the first quarter of 2018.

NGL revenue. For the six months ended June 30, 2018, NGL revenues were $3.7 million compared to $2.4 million for the six months ended June 30, 2017. The increase of 51.3% was primarily driven by a 72.8% increase in our average realized NGL price partially due to higher commodity prices during the six months ended June 30, 2018 compared to the same period of 2017. Additionally, as a result of the adoption of ASC 606, our NGL revenue for the six months ended June 30, 2018 excludes certain transportation, gathering, and processing costs resulting in an increase of $0.9 million in total NGL revenue and an increase of $6.92 per Bbl in our average realized NGL price. Additionally, during the transition to a new gas purchaser at one of our fields, we were not allocated any NGL volumes from the field for two months of the second quarter of 2018, resulting in lower NGL production volumes for the six months ended June 30, 2018 compared to the same period of 2017. To compensate for their error, we received a premium to the price for the natural gas volumes sold to the new purchaser for the two impacted months.

Production handling and other income. For the six months ended June 30, 2018, production handling and other income was $7.8 million compared to $8.7 million for the six months ended June 30, 2017. During the six

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months ended June 30, 2017, we recognized a one-time riser use fee of $1.8 million as a result of an amendment to the Petronius production handling agreement. We did not recognize a similar fee during the six months ended June 30, 2018, resulting in a decrease in production handling and other income for the six months ended June 30, 2018 compared to the same period of 2017.

Operating Expenses

The following table presents the components of our operating expense for the periods indicated:

	Six months ended June 30,
	2018		2017		Change			% Change
	(In thousands, except operating expenses per Boe and percentages)
Lease operating expenses	$	41,967	$	54,510	$	(12,543	)		(23.0	)%
Workover, repair, and maintenance expenses		11,985		8,829		3,156			35.7	%
Transportation, gathering, and processing costs		5,265		—		5,265			100.0	%
Depreciation, depletion, and amortization		96,473		88,911		7,562			8.5	%
General and administrative expenses		24,820		19,617		5,203			26.5	%
Accretion of asset retirement obligations		17,136		15,198		1,938			12.8	%
Total operating expenses	$	197,646	$	187,065	$	10,581			5.7	%
Operating expenses per Boe:
Lease operating expenses	$	7.87	$	10.59	$	(2.72	)		(25.7	)%
Workover, repair, and maintenance expenses	$	2.25	$	1.72	$	0.53			30.8	%
Transportation, gathering, and processing costs	$	0.99	$	—	$	0.99			100.0	%
Depreciation, depletion, and amortization	$	18.09	$	17.27	$	0.82			4.7	%
General and administrative expenses	$	4.65	$	3.81	$	0.84			22.0	%
Accretion of asset retirement obligations	$	3.21	$	2.95	$	0.26			8.8	%
Total operating expenses per Boe	$	37.06	$	36.34	$	0.72			2.0	%

Lease operating expenses. For the six months ended June 30, 2018, LOE was $42.0 million compared to $54.5 million for the six months ended June 30, 2017. LOE per Boe decreased from $10.59 per Boe for the six months ended June 30, 2017 to $7.87 per Boe for the six months ended June 30, 2018. The decrease of 23.0% in total LOE and 25.7% in LOE per Boe was primarily driven by realized operating cost savings related to the properties acquired from Shell resulting from increased operating efficiencies in the first quarter of 2018 compared to the same period of 2017 and lower variable operating expenses related to certain of our non-core fields.

Workover, repair, and maintenance expenses. For the six months ended June 30, 2018, workover, repair, and maintenance expenses was $12.0 million compared to $8.8 million for the six months ended June 30, 2017. Workover, repair, and maintenance expenses per Boe increased from $1.72 per Boe for the six months ended June 30, 2017 to $2.25 per Boe for the six months ended June 30, 2018. These increases were primarily driven by non-recurring costs of approximately $5.0 million incurred at the Brutus platform for services related to an anti-corrosion program, coil tubing workover, and required underwater inspections offset with lower workover, repair, and maintenance activities in our other fields.

Transportation, gathering, and processing costs. As a result of the adoption of ASC 606, transportation, gathering, and processing costs were $5.3 million for the six months ended June 30, 2018. Prior to the adoption of this standard on January 1, 2018, certain transportation, processing, and gathering costs were presented net in oil, natural gas, and NGL revenues. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 2—Basis of Presentation and Summary of Significant Accounting Policies—Revenue—Adoption of ASC 606” for further discussion of the adoption of ASC 606.

Depreciation, depletion, and amortization. For the six months ended June 30, 2018, total DD&A was $96.5 million compared to $88.9 million for the six months ended June 30, 2017. DD&A per Boe increased from

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$17.27 per Boe for the six months ended June 30, 2017 to $18.09 per Boe for the six months ended June 30, 2018. These increases were driven by an increase in the balance of oil and natural gas properties subject to DD&A and an increase in our production volumes during the six months ended June 30, 2018 compared to the same period of 2017.

General and administrative expenses. For the six months ended June 30, 2018, G&A expenses were $24.8 million compared to $19.6 million for the six months ended June 30, 2017. G&A expenses per Boe increased from $3.81 per Boe for the six months ended June 30, 2017 to $4.65 per Boe for the six months ended June 30, 2018. The increase of 26.5% in total G&A expenses and 22.0% in G&A expenses per Boe was due to an increase in accounting, other professional fees, compensation expense, general office expenses, and non-cash stock-based compensation expense.

Accretion of asset retirement obligations. For the six months ended June 30, 2018, accretion of asset retirement obligations increased slightly to $17.1 million compared to $15.2 million for the six months ended June 30, 2017. Accretion of asset retirement obligations per Boe increased from $2.95 per Boe for the six months ended June 30, 2017 to $3.21 per Boe for the six months ended June 30, 2018. These increases were primarily driven by the compounding impact of accreting the asset retirement obligations balance that is then subject to accretion.

Other Expenses

Interest expense. For the six months ended June 30, 2018, interest expense was $37.6 million compared to $29.8 million for the six months ended June 30, 2017. The $7.8 million, or 26.2%, increase in interest expense was primarily driven by the changes resulting from the 2018 Refinancing Transactions completed in February 2018, in which we incurred $8.0 million of debt issuance costs associated with the 2023 Notes and recognized $2.7 million of modification costs related to the Second Lien Term Loan. Additionally, we recognized $13.2 million in interest per the 2023 Notes contractual rate. These increases were offset with a decrease of $16.1 million in interest expense and deferred financing costs related to the Revolving Credit Facility and Second Lien Term Loan due to decreased outstanding balances during the six months ended June 30, 2018 compared to the same period of 2017 also as a result of the 2018 Refinancing Transactions. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 8—Long-term Debt” for further discussion of the 2018 Refinancing Transactions and associated transaction fees.

Loss on extinguishment of long-term debt. During the six months ended June 30, 2018, we incurred $4.0 million for loss on extinguishment of long-term debt as a result of the termination of the Second Lien Term Loan as part of the 2018 Refinancing Transactions.

Loss on fair value of the 2023 Notes. We have elected the fair value option to account for our 2023 Notes and its features and as a result, for the six months ended June 30, 2018, we recognized a loss on fair value of our 2023 Notes of $27.8 million.

(Loss) gain on derivatives, net. For the six months ended June 30, 2018, (loss) gain on derivatives, net was a loss of $(37.6) million compared to a gain of $41.1 million for the six months ended June 30, 2017. The change was attributable to a $49.0 million decrease in the fair value of our open derivative contracts as of June 30, 2018 compared to the same period of 2017 primarily as a result of the upward shift in the futures curve of forecasted oil prices during the six months ended June 30, 2018 on derivative positions outstanding at the beginning of the period. Additionally, derivative cash settlements decreased $29.8 million during the six months ended June 30, 2018 compared to the same period of 2017.

Income tax expense. For the six months ended June 30, 2018, we recognized income tax expense of $0.4 million, resulting in an effective tax rate of 10.7%. During the six months ended June 30, 2017, we recognized income tax expense of $11.5 million, resulting in an effective tax rate of 26.9%. The overall change in our effective tax rate for the six months ended June 30, 2018 compared to the same period of 2017 is due

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primarily to changes in income allocations from the underlying partnership to us and the decrease in the federal statutory rate from 35% to 21% due to the Tax Act.

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Production

The following table presents our production by product for the periods indicated:

	Year ended December 31,
	2017					2016
	Volume		% of Total			Volume		% of Total			Change		% Change
Production:
Oil (MBbls)		7,865		79.6	%		4,636		71.8	%		3,229		69.7	%
Natural gas (MMcf)		10,316		17.4	%		9,243		23.9	%		1,073		11.6	%
NGLs (MBbls)		301		3.0	%		279		4.3	%		22		7.9	%
Total production (MBoe)		9,885		100.0	%		6,455		100.0	%		3,430		53.1	%
Average daily production:
Oil (MBbls/d)		21.5		79.6	%		12.7		71.8	%		8.8
Natural gas (MMcf/d)		28.3		17.4	%		25.3		23.9	%		3.0
NGLs (MBbls/d)		0.8		3.0	%		0.8		4.3	%		—
Total production (MBoe/d)		27.1		100.0	%		17.7		100.0	%		9.4

For the year ended December 31, 2017, oil production increased by 3,229 MBbls, or 69.7%, natural gas production increased by 1,073 MMcf, or 11.6%, NGL production increased by 22 MBbls, or 7.9%, and total production increased by 3,430 MBoe, or 53.1%, compared to the year ended December 31, 2016. These increases were primarily due to the Shell Acquisition.

Revenue

The following table presents the components of our revenue, production and average sales prices for the periods indicated:

	Year ended December 31,
	2017		2016		Change		% Change
	(In thousands, except production, average sales prices and percentages)
Oil revenue	$	382,734	$	172,357	$	210,377		122.1	%
Natural gas revenue		30,233		19,636		10,597		54.0	%
NGL revenue		5,484		3,714		1,770		47.7	%
Production handling and other income		15,960		7,612		8,348		109.7	%
Total revenues	$	434,411	$	203,319	$	231,092		113.7	%
Production:
Oil (MBbls)		7,865		4,636		3,229		69.7	%
Natural gas (MMcf)		10,316		9,243		1,073		11.6	%
NGLs (MBbls)		301		279		22		7.9	%
Total production (MBoe)		9,885		6,455		3,430		53.1	%
Average sales prices:(1)
Oil (per Bbl)	$	48.66	$	37.18	$	11.48		30.9	%
Natural gas (per Mcf)	$	2.93	$	2.12	$	0.81		38.2	%
NGLs (per Bbl)	$	18.22	$	13.31	$	4.91		36.9	%
Average price (per Boe)	$	42.33	$	30.32	$	12.01		39.6	%

(1) Excluding effects of derivatives.

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Oil revenue. For the year ended December 31, 2017, oil revenues were $382.7 million compared to $172.4 million for the year ended December 31, 2016. The increase of 122.1% was partially driven by a 69.7% increase in production volumes primarily as a result of the Shell Acquisition and a 30.9% increase in our average realized oil price due in part to higher commodity prices in 2017 compared to 2016.

Natural gas revenue. For the year ended December 31, 2017, natural gas revenues were $30.2 million compared to $19.6 million for the year ended December 31, 2016. The increase of 54.0% was partially driven by an 11.6% increase in production volumes primarily as a result of the Shell Acquisition and a 38.2% increase in our average realized natural gas price due in part to higher commodity prices in 2017 compared to 2016.

NGL revenue. For the year ended December 31, 2017, NGL revenues were $5.5 million compared to $3.7 million for the year ended December 31, 2016. The increase of 47.7% was primarily driven by a 36.9% increase in our average realized NGL price due in part to higher commodity prices in 2017 compared to 2016.

Production handling and other income. For the year ended December 31, 2017, production handling and other income was $16.0 million compared to $7.6 million for the year ended December 31, 2016. The increase is driven by increased production handling agreements and pipeline revenue primarily as a result of the Shell Acquisition.

Operating Expenses

The following table presents the components of our operating expense for the periods indicated:

	Year ended December 31,
	2017		2016		Change			% Change
	(In thousands, except operating expenses per Boe and percentages)
Lease operating expenses	$	97,560	$	67,918	$	29,642			43.6	%
Workover, repair, and maintenance expenses		18,642		12,754		5,888			46.2	%
Depreciation, depletion, and amortization		170,372		104,584		65,788			62.9	%
General and administrative expenses		42,397		35,078		7,319			20.9	%
Accretion of asset retirement obligations		31,392		21,669		9,723			44.9	%
Total operating expenses	$	360,363	$	242,003	$	118,360			48.9	%
Operating expenses per Boe:
Lease operating expenses	$	9.87	$	10.52	$	(0.65	)		(6.2	)%
Workover, repair, and maintenance expenses	$	1.89	$	1.98	$	(0.09	)		(4.5	)%
Depreciation, depletion, and amortization	$	17.24	$	16.20	$	1.04			6.4	%
General and administrative expenses	$	4.29	$	5.43	$	(1.14	)		(21.0	)%
Accretion of asset retirement obligations	$	3.17	$	3.36	$	(0.19	)		(5.7	)%
Total operating expenses per Boe	$	36.46	$	37.49	$	(1.03	)		(2.7	)%

Lease operating expenses. For the year ended December 31, 2017, LOE was $97.6 million compared to $67.9 million for the year ended December 31, 2016. The increase of 43.6% in total LOE was primarily due to the Shell Acquisition. While total LOE increased, LOE per Boe decreased from $10.52 per Boe for the year ended December 31, 2016 to $9.87 per Boe for the year ended December 31, 2017. The decrease of 6.2% in LOE per Boe was driven by disproportionately higher production volumes as a result of the Shell Acquisition compared to total LOE during the year ended December 31, 2017. During this same period, our company-wide ratio of reportable incidents decreased by approximately 40%.

Workover, repair, and maintenance expenses. For the year ended December 31, 2017, workover, repair, and maintenance expenses were $18.6 million compared to $12.8 million for the year ended December 31, 2016. The increase of 46.2% in total workover, repair, and maintenance expenses was attributable to an increase of

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$3.3 million related to our Brutus field acquired in the Shell Acquisition and an increase of $3.9 million related to increased activity at our Cognac and Petronius fields. This increase was partially offset by a decrease in expenses related to the Lobster field. While total workover, repair, and maintenance expenses increased, workover, repair, and maintenance expenses per Boe decreased from $1.98 per Boe for the year ended December 31, 2016 to $1.89 per Boe for the year ended December 31, 2017. The decrease of 4.5% in workover, repair, and maintenance per Boe was driven by disproportionately higher production volumes primarily as a result of the Shell Acquisition in 2016 compared to total workover, repair, and maintenance expenses during the year ended December 31, 2017.

Depreciation, depletion, and amortization. For the year ended December 31, 2017, total DD&A was $170.4 million compared to $104.6 million for the year ended December 31, 2016. The increase of 62.9% in total DD&A was due to an increase in production volumes resulting primarily from the Shell Acquisition and an increase in the depletion rate of our proved properties ($17.16 per Boe and $16.06 per Boe for the years ended December 31, 2017 and 2016, respectively). While total DD&A increased by 62.9%, DD&A per Boe increased only slightly by 6.4%, from $16.20 per Boe for the year ended December 31, 2016 to $17.24 per Boe for the year ended December 31, 2017. The increase of 6.4% in DD&A per Boe was driven by the disproportionately higher increase in the depreciable base over the increase in reserves primarily due to the Shell Acquisition.

General and administrative expenses. For the year ended December 31, 2017, G&A expenses were $42.4 million compared to $35.1 million for the year ended December 31, 2016. The increase of 20.9% in total G&A expenses primarily resulted from a $3.0 million increase in stock-based compensation expense primarily driven by increased restricted stock and stock option issuances in 2017 and a $3.7 million increase in employee, office, and travel and entertainment expenses primarily due to increased headcount resulting from acquisitions. While total G&A expenses increased, G&A expenses per Boe decreased from $5.43 per Boe for the year ended December 31, 2016 to $4.29 per Boe for the year ended December 31, 2017. The decrease of 21.0% in G&A expenses per Boe was driven by disproportionately higher production volumes primarily as a result of the Shell Acquisition in 2016 compared to total G&A expenses during the year ended December 31, 2017.

Accretion of asset retirement obligations. For the year ended December 31, 2017, accretion of asset retirement obligations was $31.4 million compared to $21.7 million for the year ended December 31, 2016. The increase of 44.9% in total accretion expense was driven by an increase in asset retirement obligations as a result of the Shell Acquisition. While total accretion of asset retirement obligations increased, accretion of asset retirement obligations per Boe decreased from $3.36 per Boe for the year ended December 31, 2016 compared to $3.17 per Boe for the year ended December 31, 2017. The decrease of 5.7% in accretion expense per Boe was driven by disproportionately higher production volumes primarily as a result of the Shell Acquisition in 2016 compared to total accretion during the year ended December 31, 2017.

Other Expenses

Interest expense. For the year ended December 31, 2017, interest expense was $60.3 million compared to $31.5 million for the year ended December 31, 2016. This 91.4% increase was primarily driven by the December 30, 2016 amendments to our Revolving Credit Facility and Second Lien Term Loan agreements and incremental borrowings outstanding under our Revolving Credit Facility and Second Lien Term Loan in connection with the Shell Acquisition. The amendments to our Revolving Credit Facility and Second Lien Term Loan agreements resulted in increased amortization of deferred financing costs and debt discount of $7.5 million. Interest expense relating the Revolving Credit Facility and Second Lien Term Loan increased $15.1 million due to incremental borrowings on our Revolving Credit Facility and the exercise of the accordion feature of our Second Lien Term Loan on December 30, 2016 used to fund the Shell Acquisition. Additionally, the Shell Acquisition increased our future P&A obligations, resulting in incremental supplemental and performance bond premium amortization of $5.7 million.

Gain (loss) on derivatives, net. For the year ended December 31, 2017, gain (loss) on derivatives, net was a gain of $5.0 million compared to a loss of $(9.2) million for the year ended December 31, 2016. The increase in

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the net gain was due to a $16.4 million increase in the net cash received for derivative settlements during the year ended December 31, 2017 compared to year ended December 31, 2016. The net cash received for derivative settlements during the year ended December 31, 2017 included a $6.8 million gain on early terminations of certain oil derivative contracts, net of upfront premiums of $1.7 million. This increase was offset with a $2.3 million decrease in the fair value of outstanding derivative contracts as of December 31, 2017 compared to December 31, 2016.

Income tax expense. For the year ended December 31, 2017, we recognized income tax expense of $14.1 million, we did not recognize any income tax expense or benefit in the year ended December 31, 2016. The difference between our effective tax rate of 60.9% and the U.S. federal statutory rate of 35% is primarily due to cash income taxes attributable to increased revenue and a change in our valuation allowance applied against deferred tax assets, which was reduced from $23.2 million as of December 31, 2016 to $16.8 million as of December 31, 2017.

Liquidity and Capital Resources

The main sources of our liquidity are cash flows from operating activities, borrowings under our Revolving Credit Facility, cash and cash equivalents on hand and the issuance of debt or equity securities. Net cash provided by operating activities for the year ended December 31, 2017 was $191.5 million, and we expect our cash flows from operating activities to increase in 2018 through the execution and expansion of our capital projects. We expect that net cash from operating activities and cash and cash equivalents will be the primary source of liquidity to fund our capital expenditures. In addition, as of June 30, 2018, we had $271.4 million of availability under our Revolving Credit Facility (after giving effect to $3.6 million of outstanding letters of credit), which remains undrawn, and $91.5 million in cash and cash equivalents on hand. We will also selectively issue debt or equity securities as needed to maintain ample liquidity as we continue to grow our business and pursue our acquisition strategy.

Our capital programs for 2018 and 2019 consist of capital expenditures in 2018 of $200 million to $250 million and capital expenditures in 2019 of $275 million to $325 million, both years exclusive of nominal annual P&A expenditures of less than $30 million. These capital programs are primarily focused on the continued development of our operated Brutus, Glider, Lobster and Cognac fields, accounting for approximately 72% and 60% of our total 2018 and 2019 capital programs, respectively. In addition, our 2018 and 2019 capital programs allocate approximately 1% and 27%, respectively, for subsea tieback projects at certain of our operated fields, approximately 19% and 11%, respectively, for other capital projects at either properties we own or items we control, and approximately 8% and 1%, respectively, for non-operated drill wells and recompletions. Based on current commodity prices, we expect to fully fund these capital programs with cash on hand and internally generated cash flows.

During the six months ended June 30, 2018, net cash provided by operating activities was $168.8 million and our capital expenditures related to our oil and natural gas capital programs, on an accrual basis, excluding P&A expenditures, were approximately $75.3 million, which included approximately $36.0 million related to the capital programs in our Brutus and Glider fields and approximately $21.7 million related to the capital programs in our Lobster field. During the six months ended June 30, 2018, we spent an additional $7.4 million to acquire several oil and natural gas leases.

Our future cash flows are subject to a number of variables, including the level of oil, natural gas and NGL production and prices and we will require significant future capital expenditures to fully develop our assets. We expect to generate future cash flow from drilling opportunities that are not associated with proved reserves in our July 31, 2018 reserve report. The failure to achieve anticipated production and cash flows from these drilling opportunities could result in a reduction in future capital spending. We cannot assure you that operations and other needed capital will be available on acceptable terms or at all. Further, our capital expenditure budget for the remainder of 2018 and for 2019 does not allocate any material amounts for increasing leasehold and adding

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additional properties. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital funding.

We could choose to defer any portion of our capital expenditures depending on a variety of factors, including, but not limited to, the success of our development activities, potential acquisition opportunities, prevailing and anticipated prices for oil, natural gas, and NGLs, the availability of necessary equipment, infrastructure, and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs, and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows.

If we require additional capital for acquisitions or any other reason, we may increase capital through borrowings under our Revolving Credit Facility, joint venture partnerships, production payment financings, asset sales, offerings of debt or equity securities, or other means. There can be no assurance that any additional capital will be available on acceptable terms or at all.

If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling program, which could result in a loss of acreage through lease expirations or we could be required to reclassify some of our reserves currently booked as proved undeveloped if we are unable to develop such reserves within five years of their initial booking. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

We expect to continue the use of commodity derivative instruments to reduce our exposure to commodity price volatility for a portion of our oil and natural gas production volumes. Under this strategy, we intend to continue entering into derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering a percentage of our estimated oil and natural gas production volumes over a one-to-three year period at a given point in time.

Cash Flows

The following table summarizes our cash flows for the periods indicated:

	Six months ended June 30,						Year ended December 31,
	2018			2017			2017			2016
	(In thousands)
Net cash provided by operating activities	$	168,799		$	85,371		$	191,482		$	26,954
Net cash used in investing activities		(82,805	)		(28,527	)		(84,759	)		(243,631	)
Net cash (used in) provided by financing activities	$	(16,413	)	$	(75,080	)	$	(99,406	)	$	242,633

Net cash provided by operating activities. Net cash provided by operating activities totaled $168.8 million and $85.4 million during the six months ended June 30, 2018 and 2017, respectively. The increase of $83.4 million during the six months ended June 30, 2018 compared to the same period of 2017 was primarily due to higher oil, natural gas, and NGL revenue primarily driven by an increase in average realized oil, natural gas, and NGL prices. Additionally, LOE decreased over the period, driven by realized operating cost savings related to the properties acquired from Shell as a result of increased cost efficiencies. These increases were offset with a decrease in net (loss) gain on derivatives, net of $78.8 million primarily due to a $49.0 million decrease in the fair value of our open derivative contracts as of June 30, 2018 compared to the same period of 2017 driven by the upward shift in the futures curve of forecasted oil prices during the six months ended June 30, 2018 period on derivative positions outstanding at the beginning of the period and a $29.8 million decrease in derivative cash settlements during the six months ended June 30, 2018 compared to the same period of 2017. Additionally, we recognized a loss of $27.8 million on the fair value of our 2023 Notes.

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Net cash provided by operating activities totaled $191.5 million and $27.0 million during the years ended December 31, 2017 and 2016, respectively. The increase of $164.5 million in net cash provided by operating activities during the year ended December 31, 2017 compared to the year ended December 31, 2016 was primarily due to higher oil, natural gas, and NGL revenue primarily driven by increased production volumes as a result of the Shell Acquisition and an increase in average realized oil, natural gas, and NGL prices. These increases were partially offset by an increase in LOE and workover, repair, and maintenance expenses primarily driven by the Shell Acquisition. In addition, net cash received for derivative settlements for the year ended December 31, 2017 increased by $16.4 million due to more favorable derivative contract positions with higher contracted volumes and realized prices compared to the year ended December 31, 2016, including a $6.8 million gain on early terminations of certain oil derivative contracts during the year ended December 31, 2017, net of upfront premiums of $1.7 million.

Net cash used in investing activities. Net cash used in investing activities totaled $82.8 million and $28.5 million during the six months ended June 30, 2018 and 2017, respectively. The increase of $54.3 million during the six months ended June 30, 2018 compared to the same period of 2017 was primarily attributable to an increase in capital expenditures for property and equipment of $48.5 million during the six months ended June 30, 2018. The majority of our capital expenditures for the six months ended June 30, 2018 were related to drilling and completion activities at the Brutus and Lobster fields. Additionally during the six months ended June 30, 2018, we acquired several oil and natural gas leases for $7.4 million.

Net cash used in investing activities totaled $84.8 million and $243.6 million during the years ended December 31, 2017 and 2016, respectively. The decrease of $158.9 million in net cash used in investing activities during the year ended December 31, 2017 compared to the year ended December 31, 2016 was primarily attributable to the cash payment of $208.5 million for the acquisition of oil and natural gas properties primarily related to the Shell Acquisition during the year ended December 31, 2016. During the year ended December 31, 2017, we received $14.0 million related to a final purchase price adjustment from Shell. We did not have any cash payments for the acquisition of oil and natural gas properties during the year ended December 31, 2017. This decrease was partially offset by an increase in capital expenditures for property and equipment of $64.6 million during the year ended December 31, 2017. The majority of the 2017 capital expenditures were related to drilling and completion activities at the Brutus and Lobster fields.

Net cash (used in) provided by financing activities. Net cash used in financing activities totaled $16.4 million and $75.1 million during the six months ended June 30, 2018 and 2017, respectively. The net cash used in financing activities for the six months ended June 30, 2018 primarily related to paydowns of our outstanding borrowings under our Revolving Credit Facility and Second Lien Term Loan by $297.5 million, offset by the issuance of the 2023 Notes of $325.0 million, excluding debt issuance costs of $8.0 million, and an additional $1.6 million related to the amendment of the Revolving Credit Facility. Additionally, we repurchased 2,149,217 shares of our Series A Preferred Stock issued to Shell in 2016 for a total of $25.8 million. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 14—Related Party Transactions” for a discussion of the repurchase of our Series A Preferred Stock from Shell. The net cash used in financing activities during the six months ended June 30, 2017 was attributable to net paydowns of our outstanding borrowings under our Revolving Credit Facility and Second Lien Term Loan of $80.6 million.

Net cash (used in) provided by financing activities totaled $(99.4) million and $242.6 million during the years ended December 31, 2017 and 2016, respectively. The net cash used in financing activities for the year ended December 31, 2017 was primarily due to the net paydowns of our outstanding borrowings under our Revolving Credit Facility and Second Lien Term Loan of $93.0 million. The net cash provided by financing activities during the year ended December 31, 2016 was attributable to proceeds from the Series A Preferred Stock Offering of $72.7 million, proceeds from the issuance of common stock of $21.3 million, and net drawdowns under our Revolving Credit Facility and Second Lien Term Loan of $162.0 million. In conjunction with the Shell Acquisition in December 2016, we issued a total of $117.2 million of Series A Preferred Stock ($44.5 million of which was issued to Shell), borrowed an additional $75.0 million under the Second Lien Term

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Loan, and had a net drawdown of outstanding borrowings under the Revolving Credit Facility of $36.8 million. These cash inflows were slightly offset by the payment of $11.6 million in deferred financing costs related to our debt and equity issuances.

Working Capital

Our working capital totaled $41.8 million and $(14.8) million as of June 30, 2018 and December 31, 2017, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. As of June 30, 2018, our cash balance was $91.5 million. Due to the amounts we accrue related to our drilling program, we could in the future, and have in the past, incurred working capital deficits. We expect that our cash flows from operating activities, the net proceeds from this offering and availability under our Revolving Credit Facility will be sufficient to fund our working capital needs through the end of 2018. We expect that our pace of development, production volumes, commodity prices, and price differentials to NYMEX WTI and HH prices for our oil, natural gas, and NGL production will be the largest variables affecting our working capital.

Other Significant Sources of Liquidity

Revolving Credit Facility

Our Revolving Credit Facility is secured by substantially all of our assets on a first lien basis. As part of the 2018 Refinancing Transactions, we used a portion of the net proceeds from the 2023 Notes Offering to repay all of the amounts outstanding under our Revolving Credit Facility. As a result, we did not have any outstanding borrowings under our Revolving Credit Facility as of June 30, 2018. We had outstanding borrowings of $95.0 million under our Revolving Credit Facility as of December 31, 2017. Additionally, we had $3.6 million in outstanding letters of credit to collateralize our oil and natural gas transportation agreements and P&A obligations as of June 30, 2018 and December 31, 2017. During the six months ended June 30, 2018 and 2017, we recognized interest expense of $1.1 million and $4.1 million, respectively, related to the Revolving Credit Facility.

As part of the 2018 Refinancing Transactions, we amended our Revolving Credit Facility agreement to extend the maturity date to January 26, 2022 and increase the borrowing base to $231.3 million. The borrowing base is subject to semi-annual redetermination, based on an assessment of the value of our proved reserves as determined by a reserve report, and was increased to $275.0 million in June 2018 as a result of the semi-annual redetermination.

The applicable margins related to borrowings under our Revolving Credit Facility were also lowered by 0.5% as part of the 2018 Refinancing Transactions. The borrowings bear interest at one of the following rates, as selected by us: (i) the bank’s prime rate in effect, adjusted by an applicable margin of 1.75%–2.75%; or (ii) the London Interbank Offered Rate, adjusted by an applicable margin of 2.75%–3.75%. We may elect to convert outstanding borrowings to a different type and interest rate.

Revolving Credit Facility Covenants

The Revolving Credit Facility, as amended, contains certain covenants, as defined in the agreement, including maximum ratios of total funded and secured debt to EBITDAX and a minimum ratio of current assets to current liabilities. Other restrictive covenants include, but are not limited to, limitations on our ability to incur indebtedness, declare and pay dividends, make loans or investments, enter into certain hedging agreements, materially change our business, or undergo a change of control.

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The various financial ratios required by the Revolving Credit Facility covenants are described below:

Financial Covenant	Date	Required Ratio
Minimum ratio of current assets to current liabilities(1)	The last day of each fiscal quarter, beginning with the fiscal quarter ending December 31, 2017		1.00:1.00
Maximum ratio of total funded debt to EBITDAX(2)	The last day of each fiscal quarter, beginning with the fiscal quarter ending December 31, 2017		3.00:1.00
Maximum ratio of total secured debt to EBITDAX(2)	The last day of each fiscal quarter, beginning with the fiscal quarter ending December 31, 2017		2.50:1.00

(1) The Revolving Credit Facility specifies that the minimum ratio of current assets to current liabilities is calculated by comparing (a) consolidated current assets, including the unused amounts of the total commitments, but excluding non-cash derivative assets, and current plugging and abandonment restricted cash to (b) consolidated current liabilities, excluding non-cash derivative obligations, current liabilities for plugging and abandonment expense, and current maturities under the Revolving Credit Facility.

(2) The Revolving Credit Facility defines EBITDAX as, for any period, net income for the period plus the following expenses or charges to the extent deducted from net income for the period: interest, income taxes, DD&A (including the amortization of deferred financing costs), exploration expenses, accretion of asset retirement obligations, and other similar non-cash charges, less all non-cash income included in our net income. EBITDAX is subject to pro forma adjustments for any acquisitions or dispositions completed during the period, as if such acquisition or disposition had occurred on the first day of the period. Any such pro forma adjustments would also add back any non-recurring, one-time cash, or non-cash charges or expenses associated with the acquisition or disposition to net income.

The lenders may accelerate all of the indebtedness under our Revolving Credit Facility upon the occurrence of any event of default unless we cure any such default within any applicable cure period. For payments of interest under our Revolving Credit Facility, we have a three business day grace period, and a 30-day cure period for most covenant defaults, except for defaults of certain covenants, including the financial covenants and negative covenants under our Revolving Credit Facility.

Second Lien Term Loan

We also used a portion of the net proceeds from the 2023 Notes Offering to repay all of the amounts outstanding (including accrued interest and premiums) under the Second Lien Term Loan and terminated the Second Lien Term Loan as part of the 2018 Refinancing Transactions. As a result, we did not have any outstanding borrowings under our Second Lien Term Loan as of June 30, 2018. We had outstanding borrowings of $202.5 million under our Second Lien Term Loan as of December 31, 2017.

2023 Notes

As described above, on February 15, 2018, we completed the 2023 Notes Offering. The 2023 Notes were issued by our subsidiary Energy Ventures GoM LLC (the “Issuer”) and co-issued by the Issuer’s wholly-owned subsidiary, EnVen Finance Corporation. The 2023 Notes will mature on February 15, 2023 and are initially guaranteed by us and our domestic subsidiaries that guarantee the Revolving Credit Facility. The 2023 Notes and the related guarantees are secured by second-priority liens on our and the guarantors’ assets that secure all of the indebtedness under the Revolving Credit Facility, subject to certain exceptions. Interest on the 2023 Notes accrues from February 15, 2018, the date of issuance, and is paid semi-annually in cash in arrears on February 15th and August 15th of each year, beginning August 15, 2018.

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The indenture that governs the 2023 Notes contains certain covenants, agreements and events of default, which are customary with respect to non-investment grade debt securities, including limitations on our ability to incur and guarantee additional indebtedness, issue certain preferred stock or similar equity securities, pay dividends or make other distributions on, or redeem or repurchase, capital stock and make other restricted payments, prepay, redeem or repurchase certain debt, enter into certain types of transactions with affiliates, make loans or investments, enter into agreements restricting our subsidiaries’ ability to pay dividends, create liens and sell certain assets or merge with or into other companies.

The 2023 Notes indenture also contains certain put and call features that were analyzed for potential bifurcation as derivatives in accordance with ASC Topic 815, Derivatives and Hedging (“ASC 815”). One of these features grants us an option, for up to two years from the 2023 Notes issuance date, to redeem a portion of the 2023 Notes at a premium of the face value (plus any accrued unpaid interest) if we complete an equity offering (“Equity Offering Redemption Option”). We have analyzed the Equity Offering Redemption Option and have determined it is not clearly and closely related to the risks and rewards of the 2023 Notes in which it is embedded and therefore requires bifurcation. Due to this embedded derivative feature, we have elected the fair value option, in accordance with ASC 815, to account for the 2023 Notes and all of its features. Therefore, we have recorded the 2023 Notes at their fair value on the unaudited condensed consolidated balance sheet as of June 30, 2018 included elsewhere in this prospectus and the change in fair value as Loss on fair value of the 2023 Notes on the unaudited condensed consolidated statement of operations for the six months ended June 30, 2018 included elsewhere in this prospectus. At the end of each reporting period, we will remeasure the fair value of the 2023 Notes and will recognize the changes in fair value as a gain or loss on fair value of the 2023 Notes. Additionally, due to the fair value option election in accordance with ASC 815, we expensed debt issuance costs of $8.0 million associated with the 2023 Notes to Interest expense on the unaudited condensed consolidated statement of operations for the six months ended June 30, 2018 included elsewhere in this prospectus. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 2—Basis of Presentation and Summary of Significant Accounting Policies—Debt Issuance Costs” for a discussion of the 2018 Refinancing Transaction costs.

From time to time, we may seek to retire the different tranches of our debt arrangements through cash purchases and/or exchanges of equity securities, in open market purchases, privately negotiated transactions, tender offers, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts included may be material.

P&A and Decommissioning Obligations

We expect our total 2018 and 2019 P&A expenditures to be less than $30 million each year, the majority of which will be spent on abandonment costs related to legacy shallow water platforms and pipelines.

The BOEM and certain third parties require us to post supplemental and performance bonds as a means to ensure our decommissioning obligations, such as the plugging of wells, the removal of platforms and other offshore facilities, the abandonment of offshore pipelines, and the clearing of the seafloor of obstructions. We are currently in compliance with all of our financial assurance obligations to the BOEM and have no outstanding BOEM orders related to financial assurance obligations. However, we could, in the ordinary course of business, be required by the BOEM to provide future financial assurances to BOEM.

We enter into arrangements with surety companies who provide such bonds on our behalf. We may be required to provide cash collateral to support the issuance of these bonds and usually pay an annual premium in exchange for the surety’s financial strength to extend the credit. As of June 30, 2018 and December 31, 2017, we provided surety companies with cash collateral of $41.1 million and $41.0 million, respectively.

Some of the sureties could request additional collateral from us in the future, which could be significant and could impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our

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existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third-parties may require the posting of cash collateral, which may be significant, and may require the creation of escrow accounts.

Additionally, in connection with the Marathon Acquisitions, we are required to deposit approximately $100.0 million into escrow accounts to use for future P&A obligation costs assumed in the acquisitions. On the closing date of the acquisition, we deposited $30.1 million into escrow to fully fund one of the P&A obligations. The remaining funding obligation began in January 2017 and is being funded quarterly with a percentage of the gross production from the acquired properties until the relevant escrow account reaches $70.0 million. As of June 30, 2018 and December 31, 2017, the escrow balance was $12.3 million and $5.5 million, respectively, which is recorded in restricted cash on the consolidated balance sheets included elsewhere in this prospectus.

Notes Receivable

We hold notes receivable consisting of commitments from sellers of oil and natural gas properties, acquired by us, related to the costs associated with our performance of assumed long-term P&A obligations. Pursuant to agreements with the sellers, we are to receive an agreed upon amount at completion of the P&A obligations. The outstanding balances of these notes receivable were $50.3 million and $48.1 million, as of June 30, 2018 and December 31, 2017, respectively.

Contractual Obligations

As of June 30, 2018, our contractual obligations consisted of the following:

	Total		Less Than 1 Year		1-3 Years		3-5 Years		After 5 Years
	(In thousands)
11.00% Senior notes due 2023(1)	$	325,000	$	—	$	—	$	325,000	$	—
Asset retirement obligations(2)		296,726		26,751		62,964		108,827		98,184
Drilling rig contracts(3)		32,622		28,991		3,631		—		—
Operating leases(4)		1,700		1,370		330		—		—
Other long-term obligations(5)		3,723		3,719		4		—		—
Total	$	659,771	$	60,831	$	66,929	$	433,827	$	98,184

(1) The future obligations of the 2023 Notes does not include any interest expense or other fees.

(2) Asset retirement obligations excludes amounts deposited in escrow to fund the future P&A obligations assumed in the Marathon Acquisitions and post supplemental and performance bonds required by the BOEM and third parties.

(3) Includes our portion, based on working interest, of the rig preparation and daily operating rates paid to third parties for drilling activities performed at certain of our properties.

(4) Operating leases include the office leases at 333 Clay Street, Houston, TX 77002, 3850 N. Causeway Blvd., Metairie, LA 70002, and 100 Asma Blvd., Lafayette, LA 70508.

(5) As of June 30, 2018, other long-term obligations primarily includes $3.3 million of installment payments due for equipment purchased. These future obligations do not include any interest expense or other fees. Other long-term obligations also includes our portion, based on working interest, of contracted costs for turbine products and services utilized by us at certain sites.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon the financial statements included elsewhere in this prospectus. These financial statements have been prepared in conformity

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with GAAP, which requires management to make estimates and assumptions that affect the amounts reported for assets, liabilities, revenues, and expenses, and the disclosure of contingent assets and liabilities. We base our estimates on historical experience and other sources we believe are reasonable at that time. Certain estimates and assumptions we use involve judgments and uncertainties and as such, actual results may differ from the estimates and assumptions as additional information becomes known. Described below are the most significant policies and the related estimates and assumptions used by management in the preparation of our financial statements.

Oil, Natural Gas and NGL Reserves and Standardized Measure of Discounted Net Future Cash Flows

Our proved oil, natural gas and NGL reserve estimates as of December 31, 2017 and associated future net cash flows included in this prospectus have been prepared by NSAI, independent third-party reserve engineers, in accordance with the rules and regulations of the SEC by Regulation S-X, Rule 4-10. Our proved oil, natural gas, and NGL reserve estimates as of December 31, 2016 and associated future net cash flows included in this prospectus have been prepared by NSAI and Ryder Scott Company, L.P. (“Ryder Scott”), independent third party reserve engineers, in accordance with the rules and regulations of the SEC by Regulation S-X, Rule 4-10. However, Ryder Scott asserts two PUD cases included in the December 31, 2016 reserve estimates extend beyond the SEC rules in regard to being developed within five years of initially being recognized. These PUD cases were recognized by EnVen after formation of the Company in 2014.

Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. To achieve reasonable certainty, our internal reserve engineers, NSAI and Ryder Scott employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, technical and economic data including well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil, natural gas, and NGL prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas ultimately recovered.

The Standardized Measure is the present value, discounted at 10%, of estimated future net cash flows to be generated from the production of proved reserves calculated by using the 12-month unweighted arithmetic average of the first-of-the-month price for each month in the period January through December (with consideration of price changes only to the extent provided by contractual arrangements). The estimated future net cash flows are reduced by projected future development, production (excluding DD&A and any impairments of oil and natural gas properties), and P&A costs and estimated future income tax expenses. The Standardized Measure is calculated per ASC Topic 932, Extractive Activities—Oil and Gas and in accordance with SEC pricing guidelines.

Although our estimates of total proved reserves, development costs, and production rates were based on the best available information, the development and production of the oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from our estimates. Therefore, the Standardized Measure should not be considered to represent our estimate of expected revenues or the fair value of our proved oil, natural gas, and NGL reserves.

As discussed further below, our estimates of proved reserves materially impact calculated depletion expense each period; therefore, if our estimates of total proved reserves decreased, the rate at which we record depletion expense will increase, reducing earnings.

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Oil and Natural Gas Properties

We follow the full cost method of accounting for oil and natural gas activities and capitalize all costs associated with the acquisition, exploration and development of oil and natural gas properties. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals, costs of drilling, completing and equipping successful and unsuccessful oil and natural gas wells, and directly related costs. When we sell or convey interest in oil and natural gas properties, we reduce our oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on the sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves.

Certain oil and natural gas property costs represent investments in unproved properties and are excluded from costs being depleted. These costs include nonproducing leasehold, geological, and geophysical costs associated with unproved acreage and exploration drilling costs. Unproved properties and exploratory costs are excluded from the depreciable base until management determines the existence of proved oil and natural gas reserves on the respective property or the costs are impaired. We review unproved properties to determine if the costs should be reclassified and included as a part of the depreciable base at least quarterly.

The capitalized costs of proved oil and natural gas properties, net of accumulated DD&A plus estimated future development costs related to proved oil and natural gas reserves and estimated future P&A costs are amortized on a unit of production method over the estimated productive life of the proved reserves to determine DD&A for each period. DD&A related to oil and natural gas properties for the six months ended June 30, 2018 and 2017 was $96.1 million and $88.5 million, respectively. DD&A related to oil and natural gas properties for the years ended December 31, 2017 and 2016 was $169.7 million and $103.7 million, respectively.

Under the full cost method of accounting, we perform the full cost ceiling test at the end of each reporting period. Per the full cost ceiling test, net capitalized costs less deferred income taxes are limited to the present value of estimated future net cash flows from proved oil and natural gas reserves computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unevaluated properties and excluding cash flows related to estimated abandonment costs associated with developed properties (the ceiling limitation). If the net capitalized costs exceed the ceiling limitation, we recognize an impairment equal to the excess of the net capitalized costs over the ceiling limitation. No impairment was recognized for the six months ended June 30, 2018 and 2017 and the years ended December 31, 2017 and 2016.

Purchase Price Allocation in Business Combinations

We periodically pursue acquisitions of oil and natural gas properties. The assets acquired and liabilities assumed in a business combination are recognized at their respective fair values at the acquisition date. The fair value of proved properties is based on the value assigned to future recoverable oil and natural gas reserves associated with the acquired properties. If the fair value of the assets acquired and liabilities assumed is less than the purchase price, goodwill is recorded for the difference. If the fair value of the assets acquired and liabilities assumed is greater than the purchase price, a gain is recognized in earnings related to the bargain purchase.

Asset Retirement Obligations

Our investment in oil and natural gas properties include estimates of future expenditures to P&A wells and remove platforms, pipelines, and facilities after the reserves have been depleted. We record a liability at the fair value for asset retirement obligations when it is incurred (typically when the asset is installed) using a discounted cash flow model. When the liability is initially recorded, the associated asset retirement obligations cost is capitalized by increasing the carrying value of the related oil and natural gas properties.

The discounted cash flow model used to estimate asset retirement obligations fair value requires estimates relating to future P&A settlement timing and costs, a credit-risk adjusted discount rate, and inflation rates. These

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significant inputs are based on unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. Estimated costs consider historical experience, third-party estimates, and state regulatory requirements but do not consider salvage values. These costs could be subject to revisions in subsequent years due to changes in regulatory requirements, the costs to P&A wells, and the estimated timing of oil and natural gas property retirement. We either settle the obligation for our recorded amount or incur a gain or loss upon settlement, in which case the gain or loss is included in the capitalized cost of oil and natural gas properties.

Derivative Instruments

We utilize commodity derivative instruments to reduce our exposure to oil and natural gas price volatility for a significant portion of our estimated proved developed producing oil and natural gas volumes. We recognize all of our derivative instruments at fair value as either an asset or as a liability in the consolidated balance sheets included elsewhere in this prospectus.

The fair values of our derivative instruments are measured on a recurring basis using a third-party industry-standard pricing model that considers various inputs such as quoted forward commodity prices, discount rates, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant data. These significant inputs are observable in the current market or can be corroborated by observable active market data and are therefore considered Level 2 inputs within the fair value hierarchy.

We have not designated any of our derivative instruments as hedges for accounting purposes. Any gains or losses resulting from changes in the fair values of our outstanding derivatives and from the settlement of derivative financial instruments are recognized in gain (loss) on derivatives, net in the consolidated statements of operations included elsewhere in this prospectus. We typically have numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. We have elected to net our derivative instrument fair values executed with the same counterparty, pursuant to the ISDA master agreements, which provide for the net settlement over the term of the contract and in the event of the default or termination of the contract.

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

Stock-based Compensation

We recognize stock-based compensation expense related to our Restricted Stock and stock options based on the fair value of the Restricted Stock and stock options on the date of grant. Our Restricted Stock does not have any post-vesting restrictions, therefore, the fair value of each share of Restricted Stock on the date of grant is determined based on the per share fair value of our Class A common stock on a minority, non-marketable basis. The estimates of fair value of our Class A common stock are highly complex and subjective, incorporating significant judgments and estimates in the fair value assumptions. The fair value of the stock options granted is estimated at the date of grant using the Black-Scholes option pricing model.

Compensation expense related to Restricted Stock and stock options with time-based vesting is recognized using the straight-line method over the period during which the employee or board member is required to provide services in exchange for the award. Compensation expense related to Restricted Stock with performance-based vesting is only recognized when the performance condition is deemed probable of occurring. We have elected to not estimate the forfeiture rate of our Restricted Stock or stock options in our initial calculation of compensation expense, but instead will adjust compensation expense for forfeitures as they occur.

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Income Taxes

We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

As discussed in “—Known Trends and Uncertainties—Income Taxes”, we remeasured our deferred tax assets and liabilities using the new corporate tax rate as per the Tax Act, which did not impact our income tax provision or the amounts recorded on our accompanying audited consolidated balance sheets due to the offsetting effect of adjusting the valuation allowance that is applied against our net deferred tax asset. Due to various estimates included in determining the tax provision, the remeasurement is considered provisional and may be adjusted through subsequent events such as the filing of our consolidated federal income tax return for the year ended December 31, 2017.

We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize deferred income tax assets, including net operating losses. In making this determination, we consider all available positive and negative evidence and make certain assumptions. We consider, among other things, the overall business environment, our historical earnings and losses, current industry trends, and our outlook for future years. As of December 31, 2017, we believe it is more likely than not that we will not realize the benefit of our deferred tax asset and accordingly have not removed the valuation allowance. Assuming the continuation of our valuation allowance, we anticipate cash tax payments to approximately equal income tax expense for the next three years.

Our effective tax rate for the six months ended June 30, 2018 was 10.7%. The difference between our effective tax rate and the U.S. federal statutory rate of 21% is primarily due to allocations from the underlying partnership and adjustments to net income attributable to non-controlling interest. We calculate our annual effective tax rate based on current annual operating results. Our effective tax rate for the year ended December 31, 2017 was 60.9%. The difference between our effective tax rate of 60.9% and the U.S. federal statutory rate of 35% is primarily due to cash income taxes attributable to increased revenue and a change in our valuation allowance applied against deferred tax assets, which was reduced from $23.2 million as of December 31, 2016 to $16.8 million as of December 31, 2017.

Recently Issued Accounting Standards

Recently Issued Accounting Standards—Adopted

In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09 as a new ASC Topic 606, which supersedes revenue recognition requirements in ASC Topic 605, Revenue Recognition (“ASC 605”). This standard requires an entity to recognize the amount of revenue to which it expects to be entitled to for the transfer of goods or services promised to customers and requires entities to disclose the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance, including guidance pertaining to the presentation of revenues on a gross-versus-net basis and the use of the entitlements method to account for natural gas imbalances. We adopted ASC 606 effective January 1, 2018 using the modified retrospective approach, applied to contracts that were not completed as of January 1, 2018. We applied this change in accounting policy prospectively; therefore, revenues reported in periods prior to January 1, 2018 did not change.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which requires the amounts generally described as restricted cash and restricted cash equivalents to be

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included with cash and cash equivalents when reconciling the beginning of the period and end of period totals in that statement of cash flows. We adopted this standard effective December 31, 2017 using the retrospective approach.

Recently Issued Accounting Standards—Not Yet Adopted

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”), which requires an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. In February 2018, the FASB issued ASU 2018-03, Technical Corrections and Improvements to Financial Instruments (Subtopic 825-10)—Recognition and Measurement of Financial Assets and Financial Liabilities. This update was issued to clarify certain narrow aspects of guidance concerning the recognition of financial assets and liabilities established in ASU 2016-01. For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. We continue to evaluate the impact the adoption of this ASU may have on our consolidated financial statements and plan to implement this standard as required for public entities in connection to this offering.

In February 2016, the FASB issued ASU 2016-02, which will require lessees to recognize a right-of-use asset and a lease liability on their balance sheet for all leases, including operating leases, with a term of greater than 12 months. ASU 2016–02 will also require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. For public entities, ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. We continue to evaluate the impact the adoption of this ASU may have on our consolidated financial statements and plan to implement this standard as required for public entities in connection to this offering. We have engaged a third-party specialist to assist in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Standard setting guidance and interpretations continue to evolve and are being monitored for applicability and impact on our business and industry. Based on an initial review of the new ASU and our current commitments, we anticipate it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time.

JOBS Act Accounting Election

We are an “emerging growth company,” as defined in the JOBS Act. Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards issued subsequent to the enactment of the JOBS Act until such time as those standards apply to private companies. We have irrevocably elected to not avail ourselves of this exemption from adopting new or revised accounting standards.

Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks, including the effects of adverse changes in commodity prices, interest rates, and credit risk related to our oil and natural gas purchasers. Market risks refers to the risk of loss arising from adverse changes in commodity prices, interest rates, and other relevant market risks. We may enter into various derivative instruments to manage or reduce our market risk, but we do not enter into derivative instruments for speculative purposes.

The primary objective of the following disclosures is to provide quantitative and qualitative information about our potential exposure to market risk; however, they are not meant to be precise indicators of risks of losses.

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Commodity Price Risk

Our primary market risk exposure is to the prices we receive for our oil, natural gas, and NGL production. Realized prices are primarily driven by the prevailing worldwide price for oil and regional spot market prices for natural gas production. Pricing for oil, natural gas, and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depends on factors outside of our control, including physical markets, supply and demand, financial markets, and national and international policies. Based on our production for the six months ended June 30, 2018, excluding any effects of derivatives, our gross revenue for the six months ended June 30, 2018 from commodity sales would increase or decrease by approximately $43.0 million for each $10.00 per Bbl change in oil and NGL prices and $6.2 million for each $1.00 per Mcf change in natural gas prices.

In order to reduce our exposure to oil and natural gas price volatility, we utilize commodity derivative instruments to hedge a significant portion of our estimated oil and natural gas production volumes.

As of June 30, 2018, the fair value of our oil derivative instruments was a net liability of $41.6 million. Based on our outstanding oil derivatives as of June 30, 2018, a 10% increase in the NYMEX WTI average price would increase our net liability position by $27.2 million, while a 10% decrease would decrease our net liability position by $25.3 million.

As of June 30, 2018, the fair value of our natural gas derivative instruments was a net liability of $0.2 million. Based on our outstanding natural gas derivatives as of June 30, 2018, a 10% increase in the NYMEX HH average price would increase our net liability position by $1.2 million, while 10% decrease would decrease our net liability position by $1.4 million to a net asset position.

We expect to continue to use commodity derivative instruments to mitigate our exposure to price volatility in the future. Our hedging strategy and transactions will generally be determined at our discretion and may be different than our historical practice. Our Revolving Credit Facility agreement limits our derivative contracts to 85% of our estimated production from our proved developed producing oil and natural gas properties in December and January through July (“non-wind months”), and 70% of our estimated production from our proved developed producing oil and natural gas properties in August through November (“wind months”). The agreement also requires minimum hedging of 70% of our estimated production from our proved developed producing oil and natural gas properties for the first 12 months and 50% of our estimated production from our proved developed producing oil and natural gas properties for months 13 through 18 on a Boe basis, from the minimum hedging test date of March 15^th and September 15^th of each year.

See “—Known Trends and Uncertainties—Commodity Derivatives” for a listing of our outstanding commodity derivatives as of June 30, 2018.

Counterparty and Customer Credit Risk

Our use of derivative instruments exposes us to the risk that our counterparties will be unable to meet their commitments under the arrangements. We manage this risk by using multiple counterparties, all of which are lenders or affiliates of lenders participating in our Revolving Credit Facility. We monitor the creditworthiness of our derivative counterparties to determine if any credit risk adjustment is necessary to the derivative instruments fair values or if any nonperformance risk exists. Our derivative counterparties are large financial institutions with investment-grade credit ratings; therefore, we do not believe there is any significant credit risk associated with our counterparties and we do not currently anticipate any nonperformance from our counterparties.

We are also subject to credit risk due to concentration of our oil and natural gas purchasers. As of June 30, 2018, the majority of our oil production was purchased by Shell. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 14—Related Party Transactions” for further discussion of our relationship with Shell as of and for the six months ended June 30, 2018.

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We do not require our oil and natural gas purchasers to post collateral and an inability or failure of any our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We evaluate the credit standing of our oil and natural gas purchasers as we deem appropriate under the circumstances. This evaluation may include reviewing a purchaser’s credit rating, latest financial information, their historical payment record, the financial ability of the purchaser’s parent company to make payment if the purchaser cannot, and undertaking the due diligence necessary to determine credit terms and credit limits.

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to any borrowings we may have outstanding under our Revolving Credit Facility because those borrowings bear interest at market-based interest rates plus a margin based on the terms of the agreement. As of June 30, 2018, we did not have any outstanding borrowings under our Revolving Credit Facility. We do not have any other exposures to changes in interest rates as our 2023 Notes were issued at a fixed interest rate and we currently do not have any interest rate derivatives.

See “—Liquidity and Capital Resources—Other Significant Sources of Liquidity” for further discussion of our outstanding borrowings as of June 30, 2018.

Segment Reporting

We operate in one reportable segment: the oil and natural gas exploration and production industry in the U.S. All of our operations are conducted in one geographic area of the U.S. and all of our revenues are derived from customers located in the U.S.

Off-balance Sheet Arrangements

As of June 30, 2018, we did not have any off-balance sheet arrangements.

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INDUSTRY

Gulf of Mexico Overview

The U.S. Gulf of Mexico covers the area from Texas to Florida. Offshore activities in the U.S. Gulf of Mexico are typically classified based upon the drilling depth, which are organized into three categories: (i) the shelf, covering the shallow waters of the outer continental shelf in depths less than 500 feet; (ii) the deepwater, characterized by water depths between 500 feet and 7,500 feet and marking the transition from the shallow water associated with the shelf to the deeper water environment, and (iii) the ultra-deepwater, covering all depths greater than 7,500 feet. Unlike the current production generated in the shallow waters of the shelf, reservoirs in deepwater U.S. Gulf of Mexico are largely oil-dominant.

The U.S. Gulf of Mexico area is one of the nation’s largest producing oil regions and is an integral part of the U.S. energy industry. According to the EIA, crude oil production from the offshore U.S. Gulf of Mexico has increased annually every year since 2013 and reached 1.65 million barrels per day in 2017, the highest annual level on record. Additionally, federal offshore crude oil production accounted for approximately 17% of total U.S. crude oil production in 2017, second only to production from the Permian Basin. The U.S. Gulf of Mexico, like the oil industry itself, is cyclical by nature. Recently, after the lifting of the drilling moratorium in 2011, exploration and production companies resumed their exploration and development activity in the regions of the U.S. Gulf of Mexico.

Source: EIA

Given the significant historical production in the region and long history of operations over the past 40 years, an extensive network of platform and pipeline infrastructure has been developed on the continental shelf for the production, processing and export of oil and natural gas. Over 45% of total U.S. petroleum refining capacity was located along the U.S. Gulf of Mexico, along with approximately 51% of the U.S. natural gas processing plant capacity. The extensive network of midstream and downstream infrastructure allows U.S. Gulf of Mexico production to receive attractive pricing due to its proximity to demand centers and the optionality available from multiple end markets. In addition, the substantial pipeline, terminal and storage infrastructure along the U.S. Gulf of Mexico provide attractive pricing for the export of oil and natural gas production.

The commerciality of fields in the deepwater U.S. Gulf of Mexico is generally dependent on water depth, oil and natural gas prices, size of resource and the availability of existing pipeline infrastructure and hub processing facilities in the area. In response to the oil price collapse in 2014, operators have increasingly focused on decreasing operating costs and exploiting new technologies to improve economics and reduce exploration risk. One way to accomplish this is to focus on near-infrastructure projects, which have substantially better field economics due to lower capital costs and a decreased lag time from discovery to first production than new play exploration projects. Advancements in seismic imaging technology and increased utilization of predictive data analytics have also lead to smarter well placement, better well design and significant operational efficiencies that

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have ultimately reduced risks and increased drilling and development success rates in recent years. The commercial availability of wide-azimuth 3-D seismic data has provided more accurate images than were possible before, and has meaningfully enhanced the quality of data used to identify previously unknown or uneconomic prospects.

In recent years, a number of independent operators, including ConocoPhillips, Marathon Oil, Freeport-McMoRan, and Apache have either abandoned their U.S. Gulf of Mexico programs altogether or divested assets. Of the large operators that remain active in the U.S. Gulf of Mexico, many have responded by focusing on a few large high-impact ultra-deepwater projects. Additionally, we believe that some large operators are motivated to accelerate the divestiture of select under-exploited deepwater assets. We intend to focus on the deepwater region for near-term acquisitions in order to capitalize on the opportunities created by current market conditions.

Regulatory Oversight

The key federal regulatory bodies responsible for offshore exploration and production in the U.S. Gulf of Mexico are the BSEE and the BOEM. The BSEE’s core functions include research, permits, inspections, regulatory programs, spill response, and environmental compliance. The BOEM is responsible for lease sales, planning, environmental studies and analysis, resource evaluation and economic analysis.

Other agencies having jurisdiction over hydrocarbon exploration, development, and production operations in the U.S. Gulf of Mexico include: the EPA, the Department of Transportation (the “DOT”), the Department of Homeland Security, the United States Coast Guard, the US Army Corps of Engineers, and the FERC.

Leasing

Oil and natural gas exploration and development rights are granted through the allocation of specific “leases,” generally on the basis of one lease per block (or tract). Leases are allocated, usually on a cash-bid basis via semi-annual lease sales. Lease allocation and management are administered by the BOEM. Bid submissions can be made by authorized companies at any time up to the day preceding the sale. The successful bidders are announced at the lease sale, at which time full payment of the non-refundable cash bonus is due. Lease awards are only formalized once the BOEM is fully satisfied that the high bid amount for each lease is at least equal to the fair market value of that lease.

Number of Lease Sale High Bids by Year

Source: BOEM

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The primary term of a lease is five, seven or ten years, depending upon the water depth and the date of the lease award. The lease must be relinquished in full at the end of its primary term, unless production from the lease has commenced, or permission to extend the lease beyond its primary term is obtained from BOEM. A lease is ‘held by production’ for an indefinite period from initial production until production ceases.

Plugging and Abandonment

When a well reaches the end of its useful life, whether because reserves are depleted or are simply uneconomic to produce, it is plugged and abandoned. The P&A process can vary depending on age, water depth, and platform type, but generally involves removing the completion or production string, setting plugs and cement barriers at specified depths to act as permanent barriers, and disassembling and removing any subsea and surface equipment. Operators are obligated to leave the well in a condition that protects both the downhole and surface environments in perpetuity. The costs and future liabilities associated with P&A can vary widely, so managing them is a critical component of operating in the U.S. Gulf of Mexico.

The operator is responsible for the actual P&A process and thus exercises a degree of control over the costs associated with it. As the decision to P&A a well is primarily an economic one, the operator also has the ability to defer P&A expenses by extending the economic life of the well or platform. There are a number of methods to extend the economic life of a well, including having successful projects that add proved producing reserves and experience production above currently booked proved reserves. The most common methods include recompletions and side-tracks.

Similarly, operators can extend the economic life of production platforms by leveraging excess capacity to produce hydrocarbons in nearby fields. There are many fields in the U.S. Gulf of Mexico that are simply not large enough to justify the expense of new dedicated production infrastructure. Rather than let such fields lie fallow, operators can take advantage of existing infrastructure by deploying subsea tiebacks, whereby production from nearby fields is tied-back to existing production platforms. With excess production capacity available at their platforms, operators can host production from fields they own or from fields owned by other companies through production handling agreements. These production handing agreement opportunities can defer P&A obligations for the duration of the contract and present operators with incremental revenue streams without the need for additional capital to be spent.

Infrastructure

Pipeline infrastructure and hub processing facilities play an important role in the development of the deepwater U.S. Gulf of Mexico. After the discovery of major deepwater oil and natural gas reserves throughout the 1980s and 1990s, developers began to install deepwater oil and natural gas pipelines to collect, produce, process and export oil and natural gas from the shelf and deepwater U.S. Gulf of Mexico. Pipelines throughout the U.S. Gulf of Mexico deliver offshore production to refineries and major interstate pipeline hubs along the Louisiana and Texas coastlines. The pipelines vary from purpose-built, field-specific systems, such as the Ram-Powell Oil Pipeline and the SEKCO Oil Pipeline, to shared gathering systems, such as the Poseidon Oil Pipeline and the Mardi Gras Oil and Gas Transportation System. Over the years, major deepwater pipeline ‘corridors’ have been established across the U.S. Gulf of Mexico, serving numerous deepwater blocks including Viosca Knoll, Mississippi Canyon, Green Canyon, and Garden Banks, where the majority of the Company’s assets are located.

Regulation of this infrastructure development activity has been divided primarily between the BSEE, BOEM, and the DOT. BSEE and BOEM retain responsibility for producer-operated facilities and pipelines, while the DOT oversees transmission pipelines and associated pumping and compressor facilities.

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Major Oil Transportation Pipelines

Reserves and Production

The extent of existing discovered offshore U.S. Gulf of Mexico reserves and the estimates of remaining undiscovered resources offer significant potential for continued production growth. According to the BOEM, estimates of technical recoverable resources in the U.S. Gulf of Mexico that have yet to be discovered range from approximately 40 to approximately 60 billion barrels.

Offshore U.S. Gulf of Mexico Discovered Production by Water Depth

Source: BOEM

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Annual U.S. Gulf of Mexico Production (MMBoe)

Source: EIA

While unconventional U.S. onshore production has recently come to play a larger role in short-term market dynamics, conventional offshore production from the U.S. Gulf of Mexico is expected to continue to play a critical role in the global supply outlook. The U.S. Gulf of Mexico is currently the second largest oil producing basin in North America behind the Permian in terms of annual production. BOEM forecasts total annual oil production from the U.S. Gulf of Mexico in 2018 will be approximately 607 million barrels, an increase of nearly 4 million barrels from 2017. This would set a new record high for the basin and extend the trend of increased annual production volumes from the U.S. Gulf of Mexico to five consecutive years (2014-2018). According to the BOEM, the trend of increased annual oil production is expected to continue through 2024, as the contribution of oil production volumes from new and existing fields in deep and ultra-deepwater are expected to increase at a rate of 1 to 10 million barrels per year higher than the expected decline in oil production from existing fields and new discoveries in shallow water.

This growth is driven primarily by high-impact, ultra-deepwater projects undertaken by the supermajor oil companies. Projects like these require significant upfront capital investment and long lead-times before first production. Among the large projects that recently came online, Stampede (Hess), Stones (Shell), Tahiti (Chevron), Mars (Shell), and Thunder Horse (BP) are projected to add over 60 million barrels of production in 2018, accounting for nearly half of the growth in production from 2017. Production is expected to set another record in 2019, driven by two other large projects, Appomattox (Shell) and Big Foot (Chevron). On the heels of successful recent discoveries like these, the supermajor oil companies have increasingly begun to refocus their U.S. Gulf of Mexico portfolios, divesting older deepwater assets to focus primarily on new, high-impact, ultra-deepwater discoveries.

Recent Major Oil and Natural Gas Discoveries in the U.S. Gulf of Mexico

Source: Wood Mackenzie, company press releases

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The Current U.S. Gulf of Mexico Landscape

While the supermajor oil companies continue to pursue capital intensive, early-stage development projects in the ultra-deepwater, we are focused on capital efficiency, low risk and shorter lead time projects in the deepwater. As supermajor oil companies divest their legacy deepwater fields to refocus in the ultra-deepwater, other U.S. Gulf of Mexico operators like us are able to acquire and re-develop these often under-exploited deepwater assets with infrastructure led development. The legacy fields we target are typically later in life, have multiple years of productive inventory remaining and, importantly, are located near existing production and transportation infrastructure. As a result of our transactions primarily with Shell and Marathon, we acquired producing fields, as well as the production platforms used to develop them, which we estimate prior owners had invested approximately $4 billion.

Proximity to existing infrastructure has become increasingly important in the current U.S. Gulf of Mexico landscape, as it is one of the most effective ways to reduce costs and shorten lead times to first production. The importance of existing infrastructure is evidenced not only in legacy producing asset sales, but also in recent leasing activity. In Lease Sale 250 in March of 2018, approximately 40% of the bids were on leases in Mississippi Canyon and Green Canyon, two protraction areas with substantial existing production infrastructure. Leases near infrastructure allow operators to pursue projects like subsea tie-backs. When compared to early-stage discovery projects, these types of near-infrastructure projects often have lower breakevens and higher geologic success rates.

There are a number of other factors helping to lower the costs of operating in the U.S. Gulf of Mexico. As consolidation in the basin continues, there are fewer operators to contract the legacy floating drilling fleet. As a result, current dayrates for drilling rigs are nearly 60% below historical averages. By 2020, Wood MacKenzie estimates that only approximately 25% of the U.S. Gulf of Mexico floating drilling fleet will still be working at legacy day rates. Technological innovation is also playing an increasing role in the cost structure of operating offshore. Offshore equipment manufacturers like TechnipFMC have developed standardized equipment for subsea tie-backs. When compared to custom, project-specific designs, standardized equipment reduces operators’ cost of ownership and can be deployed more quickly. Technology is enabling longer tie-backs, which significantly improve project economics. Finally, seismic technology, critical in reducing the geologic risk of new developments, continues to improve allowing operators to optimize well placement and uncover additional reserves.

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BUSINESS

Our Company

We are an independent oil and natural gas company engaged in the development, exploitation, exploration and acquisition of primarily crude oil properties in the deepwater region of the U.S. Gulf of Mexico. We focus on acquiring and developing operated, deepwater assets that we believe have untapped, lower-risk drill bit opportunities and will provide strong cash flow and significant production potential. This strategy allows us to benefit from the favorable geologic and economic characteristics of the deepwater U.S. Gulf of Mexico fields.

Our portfolio of assets provides us with multiple ways to organically grow our business. Similar to acreage in prolific onshore basins, such as the Permian Basin, much of our acreage is prospective for oil and natural gas production from multiples zones, or stacked-pay, which, using advanced seismic and drilling technology provides us with additional development and production enhancement opportunities within existing and new wellbores. Our portfolio of assets includes multiple years of already identified and potentially high-return projects. These projects include sidetracks, recompletions and new drill wells, most of which are located at or near the production infrastructure we own. In addition, we expect much of our probable and possible reserves will convert to proved reserves through production outperformance, with minimal incremental capital spend. In the past, we have experienced production outperformance of our 1P reserves because of the high threshold for classification as 1P reserves. Many of our wells have previously experienced production from reserves previously categorized as probable and possible reserves without any incremental capital spend. While the probability of production may not have been sufficient to classify such reserves as 1P upon initial classification, as the wells produce in excess of the original 1P estimate, the probable and possible reserves are upgraded to 1P reserves.

We have a proven track record of executing transformative, direct negotiated acquisitions, having twice doubled our production and reserves in two asset transactions over the past three years. Targeting assets with quality production infrastructure allows us to further our hub and spoke infrastructure strategy that leverages our abilities to enhance operational efficiency, reduce costs, and increase our third-party production handling revenue through under-utilized processing facilities. Our focus on the deepwater region and our operational efficiency in the region also provides us with opportunities to acquire additional assets that we expect will provide risk-adjusted attractive returns on our investment. We believe these additional opportunities will arise as larger exploration and production companies are expected to continue to divest select under-exploited positions in the deepwater region in order to focus primarily on opportunities in the ultra-deepwater region of the U.S. Gulf of Mexico.

As of June 30, 2018, we held 59 leases in the U.S. Gulf of Mexico spanning approximately 282,789 gross acres (213,914 net), 18 of which have owned and operated offshore platforms and 7 of which have non-operated offshore platforms. Approximately 95% of our proved reserves as of July 31, 2018 and approximately 90% of our average daily production for the six months ended June 30, 2018 was attributable to assets located in the deepwater region. As of June 30, 2018, approximately 78% of our leasehold interests were “held by production,” and we had an average working interest of approximately 80% for our operated fields and approximately 31% for our non-operated fields. For the six months ended June 30, 2018, our daily production averaged 29.5 MBoe/d, approximately 78% of our production was oil, approximately 90% of our revenues were generated from oil production, and approximately 82% of our production was generated by assets we operate. Our average daily production for the first half of 2018 represents an increase of approximately 9% over our average daily production of 27.1 MBoe/d for the year ended December 31, 2017. For the year ending December 31, 2018, we expect our average daily production will be between 28 MBoe/d and 32 MBoe/d. Our projected production is based on our cash flows from operating, investing and financing activities, our commodity prices and historical performance of our wells and other management assumptions. As a result, this projection is subject to the risks and uncertainties described in this prospectus under “Special Note Regarding Forward-Looking Statements.” Although we believe we can successfully execute on our exploitation and development projects, risks and uncertainties including those identified in this prospectus under

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“Risk Factors,” may cause our production results to differ materially from the above projection. For the year ended December 31, 2017, we generated net income and Adjusted EBITDA of $9.0 million and $300.1 million, respectively, and for the six months ended June 30, 2018, we generated net income and Adjusted EBITDA of $3.5 million and $212.2 million, respectively. For the six months ended June 30, 2018, our ratio of Adjusted EBITDA to average daily production was approximately $40/Boe. See “Prospectus Summary—Summary Historical Consolidated Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA” for a reconciliation of Adjusted EBITDA to net income (loss).

As of July 31, 2018, based on a fully-engineered reserve report prepared by NSAI, an independent petroleum engineering firm, we had proved reserves of 56.2 MMBoe, probable reserves of 24.6 MMBoe and possible reserves of 35.2 MMBoe, with approximately 75% of our proved reserves, approximately 66% of our probable reserves and approximately 73% of our possible reserves being considered developed. As of July 31, 2018, the PV-10 value of our proved reserves was $1,178.2 million, the PV-10 value of our probable reserves was $699.6 million, and the PV-10 value of our possible reserves was $754.0 million. The PV-10 values in our July 31, 2018 reserve report are net of the estimated PV-10 costs associated with our future expected P&A liabilities. As of July 31, 2018, our proved reserves represent a reserve replacement of approximately 142% from December 31, 2017 at a finding, development and acquisition cost of approximately $9.50/Boe. See “Prospectus Summary—Summary Historical Reserve and Production Data—Non-GAAP Financial Measures—PV-10” for a reconciliation of the PV-10 value of our proved reserves to the Standardized Measure.

Our Assets and Reserves

The following table presents our oil, natural gas and NGL estimated reserves quantities and PV-10 values as of July 31, 2018, based on a fully-engineered reserve report prepared by NSAI, an independent petroleum engineering firm. In addition, the table shows our average daily production and oil production percentages for certain fields for the six months ended June 30, 2018.

	Average Daily Production for the six months ended June 30, 2018					Proved Reserves						Probable Reserves						Possible Reserves
	(Boe/d)		% Oil			Total (MMBoe)			PV-10(1)(2) (In millions)			Total (MMBoe)			PV-10(2) (In millions)			Total (MMBoe)			PV-10(2) (In millions)
Brutus field		8,709		77	%		18.7		$	364.2			5.3		$	177.0			7.3		$	165.3
Glider field		6,296		88	%		8.4			306.4			5.1			193.7			3.6			118.8
Lobster field		4,165		86	%		8.5			196.1			5.6			144.3			10.8			233.7
Petronius field		3,306		75	%		5.1			110.7			2.3			49.5			2.8			49.2
Cognac field		1,067		74	%		3.7			77.3			2.0			36.6			4.2			45.3
Other fields		5,922		67	%		11.8			102.8			4.3			84.5			6.5			107.4
Production handling agreements(3)		—		—			—			20.7			—			14.0			—			34.3
Total		29,465		78	%		56.2		$	1,178.2			24.6		$	699.6			35.2		$	754.0
Percentage developed reserves							75	%		81	%		66	%		63	%		73	%		72	%

(1) Proved reserve PV-10 value is a non-GAAP measure and differs from the Standardized Measure, the most directly comparable GAAP financial measure, because the proved reserve PV-10 value does not include the effects of income taxes on future net revenues, discounted at 10%, but includes the future net revenues from production handling agreements, discounted at 10%. Neither the proved reserve PV-10 value nor the Standardized Measure represents the fair value of our proved oil, natural gas and NGL reserves. See “Prospectus Summary—Summary Historical Reserve and Production Data—Non-GAAP Financial Measures—PV-10” for a reconciliation of our proved reserve PV-10 value to the Standardized Measure.

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(2) The PV-10 value of our proved reserves is presented net of the estimated costs associated with our future expected P&A liabilities with a PV-10 of approximately $152.9 million. Our probable and possible reserve PV-10 values do not have any associated incremental future expected P&A liabilities; however, the estimated timing of when the P&A liabilities will be incurred could be delayed by the probable and possible incremental production volumes.

(3) Production handling agreements relate to estimated future net revenues contracted with third parties under certain contractual arrangements. The PV-10 values vary by reserve category based on NSAI’s assumption for contract termination. Under existing agreements, $20.7 million is expected to be received through December 31, 2020; an additional $14.0 million is expected to be received through December 31, 2024; and an additional $34.3 million is expected to be received through December 31, 2028.

In the past, we have frequently been able to outperform our initial proved reserve estimates, with actual production quantities and PV-10 values exceeding those originally represented in our third-party reserve reports. Because SEC methodology for booking proved reserves limits to the lowest known hydrocarbon volumes in a wellbore and requires a 90% likelihood of ultimate production, it is common for deepwater U.S. Gulf of Mexico fields to have actual outcomes that exceed the initial proved reserve booking. As an example, our July 31, 2018 reserve report estimates that the Lobster, Petronius and Neptune fields purchased from Marathon in December 2015 will outperform the proved reserve estimates made at the time of the acquisition. Eliminating all reserve additions resulting from capital projects, our July 31, 2018 reserve report estimates an increase in proved reserves of approximately 6 MMBoe (approximately 40%) from the December 31, 2015 reserve report. We believe our history of outperforming initial proved reserve bookings substantiates our high-quality assets and our technical team’s ability to consistently evaluate and execute commercial projects successfully.

We have a substantial project inventory with unbooked hydrocarbon resources under and adjacent to our current production infrastructure and approximately 50% of our planned 2018 and 2019 capital expenditures are dedicated to developing these unbooked resources. In June 2018, we discovered over 350 feet of net pay sands in multiple intervals at our Lobster A-2 well, the majority of which is beneath the field’s current production zones. These results are evidence of our projects with unbooked resources as these deeper intervals represent significant potential reserves that are currently not included in our reserve report. Including these Lobster field projects, we have identified over 80 projects on our existing acreage that we expect will provide significant reserves to potentially add. Out of these identified projects, many have been partially de-risked due to the interpretation of recent proprietary 3-D seismic data and information obtained from previously drilled nearby wells that are comparable to the objective intervals of our projects. Moreover, we expect the vast majority of these projects to be drilled directly from our platform infrastructure or the projects are within relatively short distances from our infrastructure, which would allow for shorter development and production lead times should reserves be discovered.

Our Capital Program

Our capital programs for 2018 and 2019 consist of capital expenditures in 2018 of $200 million to $250 million and capital expenditures in 2019 of $275 million to $325 million, both years exclusive of nominal annual P&A expenditures of less than $30 million. As part of our 2018 and 2019 capital programs we expect to conduct approximately 21 sidetracks and 6 recompletions of existing wells and drill five new wells. As of July 31, 2018, we have completed five of these sidetracks and two recompletes. These capital programs are primarily focused on the continued development of our operated Brutus, Glider, Lobster and Cognac fields, accounting for approximately 72% and 60% of our total 2018 and 2019 capital programs, respectively. In addition, our 2018 and 2019 capital programs allocate approximately 1% and 27%, respectively, for subsea tieback projects at certain of our operated fields, approximately 19% and 11%, respectively, for other capital projects at either properties we own or items we control, and approximately 8% and 1%, respectively, for non-operated drill wells and recompletions. We estimate that our 2018 and 2019 capital programs have the potential to substantially increase our reserves for the years ended December 31, 2018 and 2019 and contribute approximately 14 MBoe/d to 18 MBoe/d to our 2019 year end exit rate daily production. Of the approximate 32 projects in our 2018 and 2019

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capital programs, approximately 15 target objectives with unbooked hydrocarbon resources remain to be drilled and completed. See “Business—Our Oil and Natural Gas Properties—Producing Properties and Related Projects” for a discussion of the current and planned projects at our Brutus, Glider, Lobster and Cognac fields.

The projected production from our capital programs is based on our cash flows from operating, investing and financing activities, our commodity prices and historical performance of our wells and other management assumptions. As a result, this projection is subject to the risks and uncertainties described in this prospectus under “Special Note Regarding Forward-Looking Statements.” Although we believe we can successfully execute on our exploitation and development projects, risks and uncertainties, including those identified in this prospectus under “Risk Factors,” may cause our production results to differ materially from the projections above.

The ultimate amount of capital that we expend may fluctuate materially based on market conditions and drilling results and is subject to the discretion of our management and board of directors. As approximately 96% of our expected 2018 and 2019 capital program expenditures are for projects and items that we operate, we have increased control over our overall budget and expenditures in connection with our capital program. We do not expect to incur any additional debt or use proceeds from this offering to fund our 2018 and 2019 capital programs but instead expect, assuming current oil and natural gas prices, to fully fund the programs with cash on hand and internally generated cash flows.

Our Acquisition History and Opportunity

We have a proven track record of accretive acquisitions and we will continue to proactively seek to acquire what we believe to be under-exploited deepwater assets. In December 2015, we approximately doubled our production and proved reserves through a transaction with Marathon. In December 2016, we again approximately doubled our production and proved reserves through a transaction with Shell. Both asset transactions were direct negotiations with the respective sellers and each required approximately two years from initial expression of interest to the closing of the acquisition. The assets purchased from Marathon were acquired for an estimated $6.53/Boe for proved developed producing reserves and the cumulative net cash flow of the acquired fields exceeded the effective purchase price within 16 months of the acquisition closing date, with greater than 65% of 1P PV-10 value remaining as of December 31, 2017. The assets purchased from Shell were acquired for an estimated $8.21/Boe for 1P reserves and the cumulative cash flow, less capital expenditures, of the acquired fields equaled 58% of the effective purchase price on December 31, 2017, one year after the acquisition closing date.

We believe that additional opportunities exist in the market today in the deepwater region of the U.S. Gulf of Mexico as companies prioritize their asset portfolios including larger operators choosing to focus on larger,

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more capital-intensive projects in the ultra-deepwater or companies electing to divest their U.S. Gulf of Mexico asset portfolio. Since the closing of the Shell acquisition in December 2016, we have reviewed approximately 20 potential acquisitions under non-disclosure agreements. We are proactively pursuing acquisitions of assets that in general (i) have proved developed producing reserves with further development and exploitation potential, particularly assets where our multidisciplinary technical team believes have unbooked hydrocarbon resources, (ii) have oil-weighted production, (iii) have operated assets that allow us to control operating costs, project selection, timing and costs, and the ultimate timing and costs of P&A liabilities, (iv) have accompanying infrastructure for offtake and processing, or which leverage our existing infrastructure, and (v) have the potential to be direct-negotiated transactions. We believe we are favorably positioned in the market to execute on expected future acquisitions as the industry in the U.S. Gulf of Mexico consolidates.

Our Competitive Strengths

We have a number of competitive strengths that we believe will allow us to execute our business strategies successfully and achieve our primary business objectives, including:

• High-quality, oil-focused and producing deepwater asset base. The high-quality and low risk nature of our assets provides us with a number of competitive advantages, namely a lower risk profile with significant additional development and exploration potential, reliable cash flows from long-life, lower-decline producing reserves and an opportunity to leverage the infrastructure we own to lower operating and development costs. For the three year period ended December 31, 2017, our all-in average finding, development and acquisition cost was approximately $10/Boe. In addition, we believe that much of our acreage is prospective for oil and natural gas production from multiples zones, or stacked-pay, which provides us with additional development and production enhancement opportunities within existing and future wellbores. Our Lobster A-2 well, which targeted six pay zones, is an example of the stacked-pay potential of many of our properties. Our producing assets are also heavily oil-weighted. Approximately 79% of our total proved reserves, as of July 31, 2018, and approximately 78% of our daily average production, for the six months ended June 30, 2018, consisted of oil. The oil-weighted nature of our reserves and production, and our proximity to infrastructure in the U.S. Gulf of Mexico, allows us to benefit from attractive realized pricing, especially relative to that received currently by producers in many onshore basins such as the Permian Basin. For the year ended December 31, 2017, our Adjusted EBITDA margin and net income margin were approximately 69% and approximately 2%, respectively. For the six months ended June 30, 2018, our Adjusted EBITDA margin and net income margin were approximately 69% and approximately 1%, respectively. See “Prospectus Summary—Summary Historical Consolidated Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA” for a reconciliation of Adjusted EBITDA to net income (loss).

• Ownership of extensive deepwater infrastructure. We own and operate a portfolio of geographically dispersed production facilities in the deepwater region of the U.S. Gulf of Mexico that affords us operational differentiation and opportunity access. We estimate that the deepwater infrastructure that we now own cost the original owners approximately $4 billion to construct and put into service. The development of assets drilled or accessible from our platforms allows us to achieve enhanced returns and greater cost efficiencies and reduce the time to initiate production after completing rig operations on a well. For drilling and well work conducted from a platform, we utilize platform drilling rigs that are less expensive to operate than floating drilling rigs, which allows us to achieve lower average project costs. In recent U.S. Gulf of Mexico lease sales, we acquired primary term lease blocks near our production facilities. These leases contain potential exploration opportunities we may elect to pursue, which if successful, would tie back to our facilities. Additionally, each of our deepwater production facilities has underutilized processing capacity. We use the capacity to generate additional revenue by offering third-party production processing services, which require minimal incremental operating expenditures by us. We currently have eight production handling agreements in place that generated $14.8 million of additional revenue during the year ended December 31, 2017. 

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• Multi-year inventory of attractive lower-risk drill bit projects. Our geological and geophysical professionals have identified more than 80 growth projects across our portfolio that we believe represent multiple years of inventory of lower geologic risk development and exploration opportunities. The number of independent projects in our project inventory allows us to review and prioritize the projects that we select to conduct. During the six months ended June 30, 2018, we operated multi-project development programs at our Brutus and Lobster fields. For the remainder of 2018 and 2019, we will focus our capital programs on the continued development of our operated Brutus, Glider, Lobster and Cognac fields. We expect that these multi-project programs will enable us to grow production and reserves while achieving cost and other efficiencies. Our extensive library of proprietary 3-D seismic data allows us to compare attributes of potential projects to those of known successful commercial discoveries. We believe this data reduces the geologic risk and increases the drilling success rate of our projects. We expect to be able to expand our existing project inventory with periodic field reviews, acreage obtained through lease sales and farm-in arrangements with other companies.

• Experienced and safe deepwater operator with operating control over a majority of our assets. We operate properties that generated approximately 82% of our production for the six months ended June 30, 2018 and accounted for approximately 86% of our proved reserves as of July 31, 2018. Approximately 96% of our expected capital expenditures for 2018 and 2019 are allocated to projects at either properties that we operate or items that we control. Operational control allows us to dictate the selection and pace of drilling projects, have direct control over operating costs, manage the timing and costs of our P&A liabilities, institute our safety and environmental programs and practices and more closely control risks. By following our disciplined approach to minimize expenses, after taking over the operations at the Brutus and Glider fields on December 30, 2016, we successfully reduced the annual operating costs for these fields by approximately 42% for the year ended December 31, 2017 compared to the year ended December 31, 2016. The reduced operating costs resulted from multiple actions including modifying transportation logistics and implementing multi-functional job duties. During this same period, our company-wide total reportable incident rate decreased by approximately 40% and for 2017 was approximately 64% below the published industry rate. In April 2018, in recognition of our culture of safety, we received the prestigious 2018 National Ocean Industries Association Safety in Seas Culture of Safety Award.

• Veteran senior management team with substantial U.S. Gulf of Mexico deepwater industry and technical expertise. Our senior management team has, on average, over 25 years of industry experience and has extensive expertise in deepwater geology, geophysics, drilling, well-completion, facility operations and regulatory compliance. Our senior management team collectively has executed over $25 billion of energy M&A transactions and includes members who have previously taken several energy companies public. Because of our management team’s significant operating and acquisition history as well as its experience and familiarity with the U.S. Gulf of Mexico, we believe we have a competitive advantage in sourcing and executing on attractive acquisition targets. Additionally, our senior management team has implemented governance practices appropriate for a public company.

• Strong financial position and disciplined hedging program. We pursue a disciplined financial policy with the objective of maintaining conservative leverage, strong asset coverage and ample liquidity. During the year ended December 31, 2017, we generated significant cash flow, which we used to reduce our total debt by 23.8% from $390.5 million to $297.5 million. As of June 30, 2018, the ratio of our total debt to Adjusted EBITDA for the last 12 months ended June 30, 2018 was 1.0x. See “Prospectus Summary—Summary Historical Consolidated Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA” for a reconciliation of Adjusted EBITDA to net income (loss). As of June 30, 2018, our cash balance and availability under our undrawn Revolving Credit Facility (after giving effect to $3.6 million of outstanding letters of credit), subject to the borrowing base of $275.0 million at the time, was $362.9 million. Importantly, we expect to fully fund our current capital programs, assuming current oil and natural gas prices, with cash on hand and internally generated cash flows. Our predominately fixed cost structure results in high rates of cash flows from increases in realized oil and gas prices being converted into Adjusted EBITDA. In the future years, we plan to fund

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annual capital expenditures at levels that allow us to grow production while generating positive cash flow. We also maintain an active commodity hedging program to protect our balance sheet and preserve returns on our investments from a potential decline in oil and natural gas prices, while also maintaining some upside participation in the event oil and natural gas prices rise. During the six months ended June 30, 2018, we recognized a loss of $37.6 million on our derivatives primarily due to an increase in the future commodity price outlook during the six months ended June 30, 2018.

Our Business Strategy

Our primary business objective is to provide attractive returns on invested capital while increasing reserves, production and cash flow. We intend to achieve this objective by executing the following strategies:

• Identify and execute drill bit opportunities in existing, adjacent and acquired deepwater assets. We expect to increase our production and revenue by executing projects from our existing drill bit inventory. We believe that our inventory of identified drill bit development and exploitation projects in and adjacent to our producing fields includes projects that meet our investment criteria and risk parameters for years to come. In addition, we utilize our extensive library of proprietary 3-D seismic data and local operational knowledge to identify and reduce the technical risk of potential future projects. As a result of owning considerable existing infrastructure assets, including production platforms and processing facilities, we opportunistically seek to obtain economic interests in development and exploration projects owned by other companies. We expect to fully fund our current capital programs, assuming current oil and natural gas prices, with cash on hand and internally generated cash flows.

• Leverage existing infrastructure and enhance operating efficiencies. We own and operate a large network of offshore platforms and processing facilities centered around our current producing properties that were constructed by the original owners for approximately $4 billion. Each of our deepwater platforms has available processing capacity that we plan to utilize by (i) executing our capital programs and bringing additional production online, (ii) targeting acquisitions of third-party assets and acreage available in lease sales that are accessible from our infrastructure and (iii) offering processing handling services to nearby third-party operators. This infrastructure-led growth strategy enables us to greatly reduce development costs while significantly reducing the cycle times between discovery and production. Importantly, technical improvements have allowed the industry to continue to expand the radius of potential tiebacks, making our infrastructure more valuable. In addition, our production handling agreements represent significant incremental revenue at no incremental cost to us. All of these activities help us to extend the useful life of our facilities and defer future abandonment liabilities.

• Opportunistically execute accretive acquisitions. We have a proven track record of successfully completing accretive M&A transactions with some of the largest deepwater operators, like Marathon and Shell, which we believe positions us favorably for future deals. We believe there is an emerging void in independent deepwater operators that we expect to be able to capitalize upon, and that opportunities exist to grow our business selectively through focused and strategic asset acquisitions that will provide attractive risk-adjusted returns.

• Conduct business in a safe and environmentally sensitive manner. Conducting our business in a safe and environmentally prudent manner sets the tone for our overall business performance. As such, we adhere to a strict corporate protocol of safety and environmental standards that govern our operations. In April 2018, we received the prestigious 2018 National Ocean Industries Association Safety in Seas Culture of Safety Award in recognition of the culture of safety that we have instituted while safely increasing our production and reserves and reducing operating costs.

• Maintain conservative balance sheet leverage and robust liquidity. We intend to limit our total debt and maintain robust liquidity. Additionally, we expect to maintain a hedging program that protects cash flows and allows us to fund capital plans through commodity cycles. While we seek to maintain a

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disciplined financial strategy with a conservative leverage profile, we may selectively choose to temporarily increase our leverage in order to pursue accretive transformative and/or complementary asset acquisitions. In these instances, we would expect to protect our investment returns and our balance sheet with an active hedging program.

• Proactively manage our P&A obligations and bonding requirements. As of July 31, 2018, approximately 91% of our proved reserves were located in our U.S. Gulf of Mexico deepwater fields, which are comprised of long-life, lower-decline producing reservoirs. Additionally, since we operated approximately 86% of our proved reserves as of July 31, 2018, we are able to manage the majority of our P&A obligations. Therefore, the majority of our recent and near-term P&A obligations relate to a small number of shallow water platforms. During 2017, we abandoned six legacy shallow water platforms, which were located on fields that had reached their economic life. We currently expect to spend less than $30 million per year in 2018 and 2019 to plug and abandon additional shelf fields that have reached the end of their economic life. Given the long remaining life of our deepwater fields, we do not anticipate any P&A expenditures related to our deepwater facilities before 2025, based on the proved reserve estimates in our July 31, 2018 reserve report. The PV-10 value of our proved reserves in our reserve report as of July 31, 2018 is presented net of the estimated costs associated with our future expected P&A liabilities with a PV-10 of approximately $152.9 million. As of June 30, 2018, we had approximately $150 million in place to offset the ultimate P&A obligations associated with our previous asset acquisitions. We intend to increase this amount, which consists of cash collateral for P&A bonds, cash escrow and note receivables from prior asset owners, to approximately $205 million, as we fund additional cash escrow with a percentage of net revenue from our Lobster, Petronius, and Neptune fields related to the acquisition of these assets from Marathon. Additionally, the BOEM and certain third parties require us to post supplemental and performance bonds as a means to ensure our decommissioning obligations. As of June 30, 2018, we were in compliance with these requirements and met all of our outstanding abandonment bonding demands.

Our Oil and Natural Gas Properties

For the six months ended June 30, 2018, our 23 U.S. Gulf of Mexico fields produced an average of 29,465 Boe/d net, 90% of which was generated by assets located in the deepwater U.S. Gulf of Mexico. Several of our top producing fields are described below.

We currently have an inventory of 85 identified projects on our existing acreage that we expect will provide significant reserve and production potential as we enter the next decade. We delineate this inventory in five ways:

(1) by date – 25 projects are planned in the 2018 and 2019 capital programs and 60 are planned in 2020 and beyond;

(2) by reserves – 27 projects with currently booked proved, probable or possible reserves and 58 projects that target objectives with unbooked resources;

(3) by location – 54 projects are expected to be drilled using a platform rig located on a facility we operate, 27 projects are subsea tiebacks and expected to be tied back to a facility we operate and 4 projects are expected to be drilled or tied back to a third-party facility;

(4) by activity – 16 projects are recompletions, 45 projects are sidetracks and 24 projects are new drill wells; and

(5) by operator – 81 projects we expect to operate and 4 projects we expect will be operated by a third-party.

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Several of our near-term projects included in our 2018 and 2019 capital programs are described below.

Producing Properties and Related Projects

Brutus. Our deepwater Brutus field is located in approximately 2,900 feet of water in the U.S. Gulf of Mexico Green Canyon blocks 158 and 202. We operate the Brutus field and own a 100% working interest (87.5% net revenue interest). We acquired our interest in the Brutus field from Shell in 2016.

As of July 31, 2018, Brutus had 18.7 MMBoe of proved reserves, 5.3 MMBoe of probable reserves and 7.3 MMBoe of possible reserves, net to EnVen. Average daily production for the six months ended June 30, 2018 from the Brutus field was 8,709 Boe/d net, approximately 77% of which consisted of oil. The Brutus field produces through a tension leg platform (“TLP”) owned and operated by us, with a processing capacity of approximately 145 MBoe/d. This TLP also serves as the host facility for processing production from our Glider field, as well as third-party production from the J. Bellis field operated by LLOG Exploration Company (“LLOG”). During the year ended December 31, 2017, we generated $6.8 million under production handling agreements from LLOG’s J. Bellis field production. Pipelines available in the region are the Brutus Oil Lateral (owned by EnVen), Amberjack, MARS and LOCAP for oil and Nemo, Manta Ray, and Nautilus for natural gas.

Geologically, the Brutus field is comprised of over 15 stacked, Plio-Pleistocene hydrocarbon bearing intervals, primarily between approximately 12,500 feet to 17,000 feet subsea, sub-divided and referenced as the B, C, E, G, H and J sands, which were deposited in an intra-slope mini-basin setting. As of June 30, 2018, cumulative production from the Brutus field was approximately 130 MMBoe, approximately 78% of which consisted of oil. The majority of the production since discovery has come from the deepest H and J sands. However, in addition to continuing exploitation and optimization of the H and J sands, both current and future activity in the field target the E and G sands. We apply both interpretation of our propriety 3-D seismic and information from over 40 well penetrations in the Brutus field to identify and reduce the risk of our projects.

Our operations in the field are conducted from the Brutus TLP and utilize the existing wellbores in the field to provide us with cost and operating efficiencies. In addition, the ability to use existing wellbores reduces our drilling days compared to drilling a new well and allows production to begin immediately following completion of operations. The Brutus program uses a Company-owned platform drilling rig purchased from Helmerich & Payne International Drilling Co. in 2017. Our ownership of the platform drilling rig allows us to keep the rig permanently on the TLP for effective cost management while maximizing production without rig mobilization and demobilization costs and the associated production shut-in periods.

In the third quarter of 2017, we initiated a multi-project program at the Brutus field consisting of three sidetracks and four recompletions. As of July 31, 2018, we completed two sidetracks and three recompletions of this program, with 100% geologic success, that converted 6.9 MMBoe of proved undeveloped and non-producing reserves to proved developed producing reserves and added approximately 1.6 MMBoe of proved developed producing reserves.

The Brutus program includes the A-4 project, an extended reach sidetrack project targeting an undeveloped fault block in the J-2 sand, the most prolific producer within the Brutus field. The target fault block was drilled in 2002 by Shell in the #2ST2 well during the appraisal phase of the field. The #2ST2 well encountered 85 feet of net oil pay, full-to-base, and was never produced. The proposed sidetrack is intended to twin the #2ST2 to a depth of 15,700 feet subsea. The primary risk for this project is seal/trap integrity; however, geologic, geophysical, and geochemical evidence significantly reduce this risk by substantiating that the target fault block is isolated and undrained by adjacent producing wells. This project was mapped utilizing proprietary pre-stack, depth migrated full-azimuth 3-D seismic data and at July 31, 2018 was booked as proved undeveloped reserves with a volume of 0.8 MBoe (approximately 82% oil), but with significant upside potential. We expect this project to begin in the first quarter of 2019 with initial production immediately after completion of operations. We forecast our 2018 and 2019 capital expenditures for the Brutus projects to be between $68 million and $78 million.

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After 2019, we expect to execute additional projects at the Brutus field, which will consist of sidetracks and recompletions after specific wells reach the economic life of the current producing interval. Our identified projects include three projects with proved undeveloped reserves at July 31, 2018 of 4.4 MMBoe.

Glider. Our deepwater Glider field is located in approximately 3,300 feet of water in the U.S. Gulf of Mexico Green Canyon block 248. We operate the Glider field and own a 100% working interest (87.5% net revenue interest). We acquired our interest in the Glider field from Shell in 2016.

As of July 31, 2018, the Glider field had 8.4 MMBoe of proved reserves, 5.1 MMBoe of probable reserves and 3.6 MMBoe of possible reserves, net to EnVen. Average daily production for the six months ended June 30, 2018 from the Glider field was 6,296 Boe/d net, approximately 88% of which consisted of oil. The Glider field produces through subsea completions tied back to the Brutus TLP. Shell maintained a 42% overriding interest of the production in the GL-8 well limited to the G-2 and H sands, from which the well is presently producing.

Geologically, the Glider field is syncline-separated from the Brutus field which is located seven miles northwest. The Glider field has nine primary hydrocarbon bearing intervals Pliocene in age and correlative to the reservoirs at the Brutus field. These reservoirs are subdivided and referenced as the F, G, H, I, J and L sands and primarily reside at depths between 14,000 feet and 15,500 feet subsea. Like the Brutus field, these sands were deposited in an intra-slope mini-basin setting. The H, I and J sands represent laterally extensive channelized and amalgamated sheet sands while the L sand represents a levee/overbank facies. As of June 30, 2018, the cumulative production from the Glider field was approximately 38 MMBoe, approximately 88% of which consisted of oil, with the majority of the production primarily from the G-2, H, J and L reservoirs.

The current program at Glider is to sidetrack and complete the GL-5 well. The project is planned to use the Transocean Pontus drillship to replace the J sand completion that went off-line in the existing wellbore in early 2015 due to mechanical failure. Prior to the failure, the GL-5 well was producing approximately 5,000 Boe/d with a cumulative production of approximately 8 MMBoe. The GL-5 project has 3.1 MMBoe proved, 3.0 MMBoe probable, and 2.0 MMBoe possible undeveloped reserves at July 31, 2018. We have applied 4-D seismic interpretation to our proprietary seismic data to assess the primary project risk, reservoir presence and connectivity, and to estimate the ultimate reserve potential of the reservoir. We expect the sidetrack drilling to the GL-5 project to begin in the first quarter of 2019 and with production initiated immediately following completion operations as the well remains connected to the Glider subsea manifold system. We forecast our 2018 and 2019 capital expenditures for the Glider project to be between $75 million and $85 million.

After 2019, we expect to execute additional projects at the Glider field, which will consist of sidetracks and recompletions after specific wells reach the economic life of the current producing interval. Future activity in the field is focused on continuing to optimize development in the J sand and explore development opportunities in the G and H series.

Lobster. Our deepwater Lobster field is located in approximately 775 feet of water in the U.S. Gulf of Mexico Ewing Bank blocks 873, 874, 917 and 963. We own a 66.7% working interest (55.6% net revenue interest) in Ewing Bank blocks 873, 874 and 917 and a 62.5% working interest (51.6% net revenue interest) in Ewing Bank block 963. We are the operator of the Lobster field, and Chevron is our non-operating partner. We acquired our interest in the Lobster field from Marathon in 2015.

As of July 31, 2018, the Lobster field had 8.5 MMBoe of proved reserves, 5.6 MMBoe of probable reserves and 10.8 MMBoe of possible reserves, net to EnVen. Average daily production for the six months ended June 30, 2018 from the Lobster field was 4,165 Boe/d net, approximately 86% of which consisted of oil. Lobster produces through a fixed platform structure, operated by us, with a processing capacity of approximately 80 MBoe/d. This structure also serves as the host facility for processing production from Ewing Bank blocks 917 and 963 owned by EnVen, as well as third-party production from Ewing Bank blocks 871 and 1006 operated by Walter Oil &

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Gas Corporation (“Walter Oil & Gas”). During the year ended December 31, 2017, we generated $2.3 million under production handling agreements related to production from Ewing Bank blocks 871 and 1006. Third-party pipelines available in the region are the Poseidon pipeline for oil and Discovery pipeline for natural gas.

Historically, the primary producing intervals in the Lobster field are the Plio-Pleistocene Bul 1, Cris S and the upper intervals of the Tex Mex E and H sands, encountered at depths from 9,000 feet to 12,700 feet subsea. As of June 30, 2018, the cumulative production from the Lobster field was approximately 209 MMBoe, approximately 88% of which consisted of oil. We estimate the areal extent of the Bul 1 reservoir as 1,660 acres with 160 feet of average net pay thickness. Prior to our acquisition of the Lobster field in 2015, the last well drilled in the field was in 2001. However, even without any capital expenditures, the field experienced only a historical annual average decline rate of approximately 5%.

In the second quarter of 2017, we initiated a multi-year, multi-project drilling program at the Lobster field consisting of sidetracks, recompletions and new drills. Recent and planned projects will target additional Bul 1 reservoir objectives and drill identified opportunities in the Tex Mex intervals. Prior to our acquisition the Lobster field, the Tex Mex H sand was the deepest notable producing horizon. However, our recent operating projects have identified and added to the resource potential in the deeper intervals of the field, making completions in the L, N, O and P sands. In addition, the exploratory tail of the recently drilled Lobster A-2ST2, found the S sand productive at 16,600 feet subsea with the highest quality reservoir found in the Lobster field to date.

As of July 31, 2018, we completed one recomplete and two sidetracks, with 100% geologic success, that converted 0.9 MMBoe of proved undeveloped and non-producing reserves to proved developed producing reserves since initiating the aforementioned multi-year, multi-project drilling program at the Lobster field, adding approximately 0.4 MMBoe of proved developed producing reserves. Our 2018 and 2019 capital programs at the Lobster field consist of six additional sidetracks, one recompletion, and one new drill, the majority of which target unbooked resources. We intend to conduct our operation of the Lobster field from the field platform using a platform rig contracted from Nabors Offshore Corporation (“Nabors”). Our ability to utilize existing wellbores for the majority of the projects reduces the number of drilling days. In both sidetracks and new drills, production is expected to begin within a few days following completion of rig operations.

We forecast our 2018 and 2019 capital expenditures for the Lobster projects to be between $105 million and $125 million and include the following projects:

Lobster—S Sand Acceleration

In the second quarter of 2018, the Lobster A-2ST2BP1 well discovered 114 feet net oil in the Tex Mex S sand at a depth of 16,600 feet subsea. This is the deepest hydrocarbon bearing interval and highest reservoir quality rock discovered in the Lobster field. The S Sand Acceleration project was mapped utilizing proprietary pre-stack, depth migrated full-azimuth 3-D seismic data illuminating the prospect that was not apparent on previous spec seismic interpretations. Due to pressure limitations with the existing wellhead equipment and small sized tubulars, the well was completed in the shallower Tex Mex O and P sands. We plan to develop the Tex Mex S sand with a new well with higher pressure rated wellhead equipment and larger casing and tubing to provide enhanced production rates. The project would be drilled from the Lobster platform and if successful, initial production is expected immediately following completion of drilling rig operation.

Lobster—King Crab

The King Crab project targets a stratigraphically trapped seismic amplitude of Pliocene age located in the Ewing Bank blocks 873 and 917. The target interval is approximately equivalent to the Tex Mex F sand, which to date, has not been found productive within the Lobster field. The prospective interval is likely analogous to the Tex Mex E sand which has produced approximately 9 MMBoe from the Lobster A-18 and A-24ST1BP2 wells.

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The objective depth is 14,000 feet subsea and oil is the expected hydrocarbon type. We estimate the areal extent of the targeted interval as approximately 1,750 acres with an estimated average net pay thickness of 60 feet. The primary risk for this prospect trap presence and integrity based on the offset Lobster A-21 and A-1 wells, which tested this equivalent interval as wet near the prospective seismic anomaly without full illumination of the hydrocarbon trap. This project was mapped utilizing proprietary pre-stack, depth migrated full-azimuth 3-D seismic data. The project would be drilled from the Lobster platform using a new well to allow for optimal completion rates and if successful, initial production is expected immediately following completion of drilling rig operations. A successful outcome may necessitate additional development wells and a drilling platform to recover the discovered resources. We estimate the costs to drill and complete the King Crab project to be approximately $27 million gross. If the project is unsuccessful, we expect to sidetrack the wellbore to establish production from the recently discovered Tex Mex S sand.

Lobster—Bisque

The Bisque project is a stratigraphic trap with stacked seismic amplitudes located in the northwest corner of Ewing Bank block 873. The target intervals are the Pliocene Tex Mex E and H sands, both of which have been productive in the Lobster field. The objective interval is at 10,000 feet subsea and oil is the expected hydrocarbon type. This project was mapped utilizing proprietary pre-stack, depth migrated full-azimuth 3-D seismic data. The primary risk for this prospect is compartmentalization. The project would be drilled from the Lobster platform and if successful, initial production is expected immediately following completion of drilling rig operations.

Lobster—Clam

The Clam project is a two-way fault trap with seismic amplitude support at the Pliocene-age Bul 1 reservoir interval, south of the main producing area in Ewing Bank block 917. The objective interval is at 13,300 feet subsea and consistent with Bul 1 production in the Lobster field, oil is expected as the hydrocarbon type. This project was mapped utilizing proprietary pre-stack, depth migrated full-azimuth 3-D seismic data and the primary risk for this project is trap integrity. The combined estimated mean net area of the prospective seismic anomalies is 100 acres, which is comparable to the recoverable area supported by well data and reservoir modeling for each Bul 1 producer, which has averaged approximately 9 MMBoe and approximately 6 Bcf (based on 16 wells). The seismic amplitude indicates a mean net pay thickness in excess of 100 feet, consistent with the main producing area of the field. The project would be drilled as an extended reach well from the Lobster platform and if successful, initial production is expected immediately following completion of drilling rig operation.

Lobster—Bul 1 Infill Wells

As of December 2015, when we acquired the Lobster field, the Bul 1 reservoir had produced approximately 120 MMBoe of oil and approximately 95 Bcf of natural gas from 16 wells, with average cumulative production of approximately 7 MMBoe of oil and approximately 6 Bcf of natural gas per well. The interpretation of our proprietary pre-stack, depth migrated full-azimuth 3-D seismic data and reservoir modeling support the drilling of several infill projects to fully develop section of the reservoir. The infill drill wells have targets ranging in depths from 10,200 feet to 11,800 feet depending on the location. The primary risk on these projects is reservoir connectivity. Each project would be drilled from the Lobster platform and if successful, initial production is expected immediately following completion of drilling rig operations.

Lobster—A-13 Offset

The A-13 Offset project is a combination structural and stratigraphic trap to recover reserves lost due to failure of the Lobster A-13 well completion in the Pliocene B sand. This well produced approximately 100 MBbls of oil and approximately 0.1 Bcf of natural gas with an initial oil and natural gas production rates of 970 Boe/d and 530 Mcf/d, respectively, before the completion failed. The objective depth is 9,400 feet subsea. The primary risk for the project is the reservoir quality.

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After 2019, we expect to execute additional projects at the Lobster field that consist of sidetracks, new drills, and recompletions.

Cognac. Our deepwater Cognac field is located in approximately 1,020 feet of water in the U.S. Gulf of Mexico Mississippi Canyon blocks 150, 151, 194 and 195. We own a 63.1% working interest (52.6% net revenue interest) in the Cognac field. We are the operator of the Cognac field and our non-operating partners include Apache Deepwater LLC (21.8% working interest), Chevron (13.9% working interest), and W&T Offshore, Inc. (“W&T”) (1.2% working interest). We acquired the majority of our interest in the Cognac field from Shell and ENI in 2014 and 2015, respectively.

As of July 31, 2018, the Cognac field had 3.7 MMBoe of proved reserves, 2.0 MMBoe of probable reserves and 4.2 MMBoe of possible reserves, net to EnVen. Average daily production for the six months ended June 30, 2018 for the Cognac field was 1,067 Boe/d net, approximately 74% of which consisted of oil. The Cognac field produces through a fixed platform structure, operated by us, with a processing capacity of approximately 87 MBoe/d. Pipelines available in the region are the Cognac Oil Lateral for oil and Discovery pipeline for natural gas.

Geologically, the Cognac field consists of 32 Pleistocene through Upper Miocene hydrocarbon bearing intervals, primarily between 4,200 feet and 12,000 feet subsea. These intervals are subdivided and referenced as the D, E, F, G, H, I, J, K, L, M and PM-5 sands. The shallowest producing Cognac sands, the Do through G-3 sands, are amalgamations of turbidite distributary systems (i.e., incised channels and sheets), ranging in age from Early Pleistocene through Middle Pliocene where the approximate boundary between Upper Pliocene and Lower Pliocene is placed below the G-3 sand. Beginning in the top of the Lower Pliocene with G-4 sand and extending through the K-3, sand deltaic deposition dominates. The Early Pliocene L and M series sands are interpreted as amalgamations of outer shelf turbidite channels, sheets, and levees. The Upper Miocene sands are relatively undeveloped and consist of deltaic and composite channel complexes.

As of June 30, 2018, cumulative production from the Cognac field was approximately 309 MMBoe, approximately 59% of which consisted of oil, with approximately 80% of this production was generated from the Lower Pliocene G-4 through K-3 sands. Future activity in the field will continue to develop the primary reservoirs, continue to expand development opportunities in the Upper Miocene and investigate the exploration potential within the deeper, Middle Miocene. We apply both interpretation of multiple 3-D seismic volumes and information from over 215 Cognac field well penetrations to identify and reduce the risks of our projects. We are currently in the final stages of a 3-D seismic data merge to create a proprietary seismic volume to further refine and high-grade the project inventory.

In the first quarter of 2019, we plan to mobilize a platform rig to commence a multi-year, multi-project drilling program at the Cognac field consisting of 13 sidetracks. Our 2018 and 2019 capital programs at the Cognac field consist of four sidetracks, three of which target unbooked reserves. We will conduct our drilling operations at the Cognac field from the field platform using a platform rig contracted from Nabors. Our ability to utilize existing wellbores (sidetracks and recompletions) reduces the number of drilling days compared to drilling a new well and allows production to begin within a few days following completion of rig operations.

We forecast our 2018 and 2019 capital expenditures for the Cognac projects to be between $72 million and $85 million and include the following projects:

Cognac—A-7 ST3 (Location 1)

The A-7 ST3 (Location 1) project is an extended reach sidetrack targeting an isolated fault block on the northeastern section of the Cognac field. The objective of the project is to test the updip intervals in the Pliocene I, Jo, and J sands that are three of the more prolific reservoirs in the Cognac field. The project was mapped utilizing non-proprietary reprocessed, pre-stack, depth migrated narrow-azimuth 3-D seismic data. The primary

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risk for this prospect is finding gas. Target intervals range from 6,400 feet to 6,750 feet subsea. At July 31, 2018, the A-7 ST3 (Location 1) project had 1.1 MMBoe proved, 0.9 MMBoe probable, and 1.1 MMBoe possible undeveloped reserves.

Cognac—KRZ (Location 2)

The KRZ (Location 2) project targets an amplitude-supported structural trap in the Pliocene K, L-2, and M sands between 9,650 feet and 10,500 feet subsea. The K sand is one of the more prolific producers in the field. This project was mapped utilizing non-proprietary reprocessed, pre-stack, depth migrated narrow-azimuth 3-D seismic data. The hydrocarbon type is anticipated to be oil, with the possibility of gas-condensate. The primary risk for this project is trap integrity. The project will be drilled using the platform rig and if successful, initial production will immediately follow completion of drilling rig operations. Additional upside exists in the shallow section in the Pliocene G-3 sand, as the offset Cognac A-40 well, experienced a failed completion after producing 6.5 Bcf and 469 MBbls with less than 25% reduction in bottom-hole pressure.

Cognac—Hennessey

The Hennessey project is targeting a stratigraphic seismic amplitude of Upper Miocene age that is deeper than any productive interval at the Cognac field. The prospective interval is expected to be analogous to the Upper Miocene PM-5 sand produced from the Cognac A-24 ST2BP1 well, which produced 11.8 Bcf and 264 MBbls from a smaller seismic anomaly. The hydrocarbon type for this prospect is anticipated to be gas-condensate, but has the possibility of being oil. This project was mapped utilizing non-proprietary reprocessed, pre-stack, depth migrated narrow-azimuth 3-D seismic data. The objective depth is 14,100 feet subsea and the primary risk for this prospect is compartmentalization. The project will be drilled using the platform rig and if successful, initial production will immediately follow completion of drilling rig operations.

After 2019, we expect to execute additional projects at the Cognac field, using the Nabors platform rig, which consist of sidetracks and recompletions.

Petronius. Our deepwater Petronius field is located in approximately 1,750 feet of water in the U.S. Gulf of Mexico in Viosca Knoll blocks 742, 786 and 830. We own a 50% working interest (43.8% net revenue interest) in the Petronius field. Chevron operates the Petronius field and also owns a 50% working interest.

As of July 31, 2018, the Petronius field had 5.1 MMBoe of proved reserves, 2.3 MMBoe of probable reserves and 2.8 MMBoe of possible reserves, net to EnVen. Average daily production for the six months ended June 30, 2018 from the Petronius field was 3,306 Boe/d net, approximately 75% of which consisted of oil. The Petronius field produces through a compliant tower structure, 50% owned by EnVen, with a processing capacity of approximately 77 MBoe/d. This structure also serves as the host facility for processing third-party production from the DeSoto Canyon blocks 4, 48, 47, 91 and 135, (the “Dalmatian field”) operated by Murphy Exploration and Production Company (“Murphy”). During the year ended December 31, 2017, we received $4.1 million under production handling agreements from Murphy related to production from Dalmatian field. Third-party pipelines available in the region are Odyssey for oil and VKGS, WGS, and Transco for natural gas.

Geologically, the Petronius field is comprised of ten stacked, Middle Miocene hydrocarbon bearing intervals, primarily between 9,800 feet to 12,000 feet subsea, sub-divided and referenced as the F, G, H, I, J-0.5, J-1, J-2, J-3, J-4 and J-6 sands. As of June 30, 2018, the cumulative production of the Petronius field was approximately 199 MMBoe, approximately 80% of which consisted of oil. The J sands accounted for essentially all of the Petronius field production. The J-1 and J-2 sands are relatively widespread amalgamated channels and unconfined radial slope fans. These are the most prolific producers within the Petronius field and account for over 78% of the field production. J-4 and J-6 sands are more limited ponded deposits localized in the southern portion of the field and comprise approximately 17% of the field production. Extended reach wells have been drilled to the north and south, referred to as Viosca Knoll blocks 742 and 830 are considered part of the greater Petronius field.

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The Petronius field is currently undergoing an active waterflood to enhance recovery and maintain reservoir pressure. This operation is active in the J-1, J-2 and J-4 sands. Future activity will concentrate on investigating exploration opportunities in the surrounding area for subsea tiebacks the facility. We do not currently have any 2018 or 2019 capital expenditures or identified project inventory associated with the Petronius field.

Neptune. Our deepwater Neptune field, is a subsea complex located in approximately 6,250 feet of water in the U.S. Gulf of Mexico Atwater Valley blocks 574, 575, and 618. We own a 30% working interest (26.3% net revenue interest) in the Neptune field. BHP Billiton Limited operates the Neptune field with a 35% working interest and our non-operating partners include W&T (20% working interest).

As of July 31, 2018, the Neptune field had 1.8 MMBoe of proved reserves, 0.5 MMBoe of probable reserves and 0.8 MMBoe of possible reserves, net to EnVen. Average daily production for the six months ended June 30, 2018 from the Neptune field was 1,438 Boe/d net, approximately 94% of which consisted of oil. The Neptune subsea complex produces through a TLP located two blocks west in Green Canyon block 613, located in 4,250 feet of water, with a processing capacity of approximately 58 MBoe/d. Third-party pipelines available in the region are the Enbridge, Caesar and Poseidon oil and Enbridge, Cleopatra, Manta Ray, and Nautilus for natural gas.

Geologically, the Neptune field is comprised of six Lower Miocene hydrocarbon bearing intervals, primarily between 16,300 feet to 18,200 feet subsea, sub-divided and referenced as the M-7, M-9, M-9C, M-9X, M-10, and M-12 sands. As of June 30, 2018, the cumulative production from the Neptune field was approximately 45 MMBoe, approximately 88% of which consisted of oil. The M-10 sand is laterally extensive, consisting of channels and amalgamated lobes of a basin floor fan system and accounts for approximately 75% of the overall Neptune field production. The M-9 interval accounts for the remaining 25% of the Neptune field total production volumes. The Neptune field is located below the Sigsbee escarpment and is partially obscured by an overlying allochthonus salt canopy that limits 3-D seismic interpretation of the northern area of the Neptune structure. Thus, all development activity to date has been in the southern flank of the field.

Current activity driven by the operator is to continue to optimize recovery from the producing wells with pressure drawdown management. We expect future activity may further develop the M-9 and M-10 sands with potential attic or infill wells, initiate development of the M-7, and potentially explore and develop the northern flank of the field. We do not currently have any 2018 or 2019 capital expenditures or identified project inventory associated with the Neptune field.

Other Long-term Projects

In addition to the projects associated with our current producing properties described above, our project inventory includes certain prospects described below.

Ridgewood Prospects. On September 7, 2018, we entered into a letter of intent with Ridgewood Energy Corporation (“Ridgewood Energy”) relating to our planned participation in the Mt. Ouray prospect, comprised of the U.S. Gulf of Mexico Green Canyon blocks 723 and 767 (the “Mt. Ouray Prospect”) and the Mt. Shavano prospect, comprised of the U.S. Gulf of Mexico Green Canyon block 722 (the “Mt. Shavano Prospect”) (collectively the “Ridgewood Agreement”). The Ridgewood Agreement is not yet effective. Assuming the Ridgewood Agreement becomes effective, we will own a 40% working interest in the Mt. Ouray Prospect, a 35% working interest in the Mt. Shavano Prospect, and we will operate both prospects.

The prospects are expected to be drilled using a floating rig and if successful, would require multi-well development. Drilling of these prospects is expected to commence in 2019.

Ewing Bank Prospect. The U.S. Gulf of Mexico Ewing Bank block 920 prospect (the “EW 920 Prospect”) is a combination structural and stratigraphic trap with seismic amplitude located approximately 8 miles east of our

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Lobster field and the anticipated hydrocarbon is expect to be oil. We are the operator of the EW 920 Prospect with a 50% working interest and Walter Oil & Gas is our 50% non-operating partner. We acquired our working interest in the EW 920 Prospect in the 2015 U.S. Gulf of Mexico lease sale.

The EW 920 Prospect targets the Lower Pliocene interval, which is anticipated at 21,000 feet subsea and offsets a hydrocarbon bearing section in an offset field. The primary prospect risks are reservoir connectivity and potential compartmentalization. The EW 920 Prospect is expected to be drilled with a floating rig. Drilling of the EW 920 Prospect is expected to commence in 2020 and if successful, may require an additional well to fully develop and would tieback to our Lobster facility.

DaVinci Prospect. The U.S. Gulf of Mexico South Pelto block 16 prospect (the “DaVinci Prospect”) is a two-way fault trap with robust seismic amplitude and the anticipated hydrocarbon type is oil. We are the operator of the DaVinci Prospect with a 50% working interest and Navitas Petroleum is our 50% non-operating partner. We acquired the DaVinci Prospect from Navitas Petroleum in 2018.

The DaVinci Prospect targets the Pliocene objective, which is analogous to a productive interval in an offset field that has cumulative production of approximately 5 MMBoe as of June 30, 2018. The primary prospect risk is trap integrity. If successful, the field would likely justify setting a caisson and may utilize topside facilities from a recently abandoned field. Drilling of the prospect is expected to commence in the fourth quarter of 2018 and we forecast our 2018 and 2019 capital expenditures for the DaVinci Prospect to be between $10 million and $15 million:

Productive Wells

The following table presents our working interest at June 30, 2018 in our productive oil and natural gas wells:

	Oil				Natural Gas				Total
	Gross		Net		Gross		Net		Gross		Net
Operated		50		40.3		14		11.6		64		51.9
Non-operated		25		8.9		10		1.3		35		10.2
Total productive wells		75		49.2		24		12.9		99		62.1

At June 30, 2018, we owned working interest in one gross active producing oil well containing multiple completions and did not own interest in any gross active producing natural gas wells containing multiple completions.

Drilling Activity

As discussed above, the majority of our historical and budgeted capital expenditure is allocated to recomplete and sidetrack development programs at existing producing locations. As a result, our development and exploration drilling activity has not been significant. During the year ended December 31, 2016, we drilled one gross (0.62 net) productive exploratory oil well and one gross (0.62 net) dry development oil well. During the year ended December 31, 2017, we drilled two gross (1.334 net) productive development oil wells and two gross (1.667 net) dry exploratory oil wells. During the six months ended June 30, 2018, we drilled three gross (2.20 net) productive development oil wells and one gross (0.667 net) productive exploratory oil well. We did not drill any other oil or natural gas wells during the years ended December 31, 2017 and 2016 or the six months ended June 30, 2018.

As of June 30, 2018, we had three gross (1.07 net) operated and non-operated oil wells, respectively, in various stages of drilling or completion, which are not included in the well counts above.

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Acreage

The following table presents our leasehold at June 30, 2018:

	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Deepwater(1)		126,200		78,046		46,080		43,200		172,280		121,246
Shelf		91,252		73,411		19,257		19,257		110,509		92,668
Total acreage		217,453		151,457		65,337		62,457		282,789		213,914

(1) Deepwater refers to acreage in the U.S. Gulf of Mexico characterized by water depths between 500 feet and 7,500 feet and marking the transition from the shallow water associated with the shelf to the deeper water environment.

Our total acreage as of June 30, 2018 does not include 28,800 gross and net acres purchased during the second quarter of 2018, which will become effective July 1, 2018. As of June 30, 2018, 33.0% of our total 65,337 gross undeveloped acreage could expire by the end of 2019, 34.1% could expire in 2020, 16.5% could expire in 2021, and 16.4% could expire in 2022 and beyond. As of June 30, 2018, 34.5% of our total 62,457 net undeveloped acreage could expire by the end of 2019, 31.1% could expire in 2020, 17.2% could expire in 2021, and 17.2% could expire in 2022 and beyond. As of June 30, 2018, none of our gross or net undeveloped acreage could expire by the end of 2018. We give consideration to undeveloped leasehold that could expire in the near term when making decisions regarding future drilling and operations. As of July 31, 2018, we had not assigned any proved undeveloped reserves to locations that are currently scheduled to be drilled after lease expiration. See “Risk Factors—Risks Related to Our Business—Our identified potential drilling locations, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.”

Title to Properties

As is customary in the oil and natural gas industry, we conduct title reviews at the time we acquire oil and natural gas properties and often procure written title reviews and title opinions of local counsel if the value of the acquisition or complexity of the underlying title warrants such analysis. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use in the operation of our business. We believe that we have satisfactory title to or rights to all of our producing properties. See “Risk Factors—Risks Related to Our Business—We may incur losses as a result of title defects in the properties in which we invest.”

Our oil and natural gas properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.

Oil, Natural Gas, and NGL Reserves

Proved Reserves

Proved reserves are those quantities of oil and natural 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. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves.

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Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil, natural gas, and NGL prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas ultimately recovered or reserve quantities reported by other entities.

We employ a technical staff of petroleum engineers and geoscientists that perform technical analysis of each of our estimated proved, probable and possible reserves. Our reserve estimates as of July 31, 2018 and December 31, 2017 are based on a reserve reports prepared by NSAI in accordance with the rules and regulations of the SEC by Regulation S-X, Rule 4-10. Our reserve estimates as of December 31, 2016 are based on reserve reports prepared by NSAI and Ryder Scott in accordance with the rules and regulations of the SEC by Regulation S-X, Rule 4-10. However, Ryder Scott asserts two PUD cases included in the December 31, 2016 reserve estimates extend beyond the SEC rules in regard to being developed within five years of initially being recognized. These PUD cases were recognized by EnVen after formation of the Company in 2014. All of our proved reserves presented below are located in the U.S. Gulf of Mexico.

NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the summary NSAI reserve reports incorporated herein are Mr. Gregory S. Cohen and Mr. Edward C. Roy III. Mr. Cohen, a Licensed Professional Engineer in the State of Texas (No. 117412), has been practicing consulting petroleum engineering at NSAI since 2013 and has over 14 years of prior industry experience. He graduated from Carnegie Mellon University in 1980 with a Bachelor of Science Degree in Chemical Engineering and from Anderson Graduate School of Management at UCLA in 1993 with a Master of Business Administration Degree. Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience. He graduated from Texas Christian University in 1992 with a Bachelor of Science degree in Geology and from Texas A&M University in 1998 with a Master of Science degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Messrs. Roy and Cohen are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI does not own an interest in us or any of our properties, nor is it employed by us on a contingent basis.

Within Ryder Scott, the technical person primarily responsible for preparing the estimates set forth in the Ryder Scott summary reserve report incorporated herein is John E. Hamlin. Mr. Hamlin has been practicing consulting petroleum engineering at Ryder Scott since 1979. Mr. Hamlin is a registered Professional Engineer in the State of Texas and has over 39 years of practical experience in the estimation and evaluation of reserves. Mr. Hamlin graduated from the University of Texas at Austin in 1975 with a Bachelor of Science degree in Petroleum Engineering. As technical principal, Mr. Hamlin meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. Ryder Scott does not own an interest in us or any of our properties, nor is it employed by us on a contingent basis.

Our reserve estimates as of July 31, 2018 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period August through July. Our reserve estimates as of December 31, 2017, and December 31, 2016 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December.

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The following table presents our estimated proved developed, proved undeveloped, and total proved oil, natural gas, and NGL reserves and PV-10 values and the Standardized Measure, based on the reserve reports prepared by NSAI, as of July 31, 2018 and December 31, 2017:

	As of July 31, 2018
	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)		Proved PV-10(1) (In thousands)
Proved developed producing reserves		27,060		34,177		1,311		34,067	$	815,391
Proved developed non-producing reserves		5,452		13,699		115		7,850		143,337
Proved undeveloped reserves		11,658		13,386		356		14,245		219,424
Total proved reserves		44,170		61,262		1,782		56,162		1,178,152
Standardized Measure(1)									$	944,451
	As of December 31, 2017
	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)		Proved PV-10(1) (In thousands)
Proved developed producing reserves		24,488		21,724		931		29,040	$	512,211
Proved developed non-producing reserves		7,247		15,510		111		9,943		184,357
Proved undeveloped reserves		11,667		15,386		385		14,616		244,005
Total proved reserves		43,402		52,620		1,427		53,599		940,573
Standardized Measure(1)									$	759,096

(1) Proved reserve PV-10 value is a non-GAAP measure and differs from the Standardized Measure, the most directly comparable GAAP financial measure, because the proved reserve PV-10 value does not include the effects of income taxes on future net revenues, discounted at 10%. The PV-10 values as of July 31, 2018 and December 31, 2017 include the future net revenues from production handling agreements of $20.7 million and $20.1 million, respectively, which we expect to receive through December 31, 2020 and 2019, respectively, discounted at 10%. Neither proved reserve PV-10 value nor the Standardized Measure represents the fair value of our proved oil, natural gas and NGL reserves. See “Prospectus Summary—Summary Historical Reserve and Production Data—Non-GAAP Financial Measures—PV-10” for a reconciliation of our proved reserve PV-10 value to the Standardized Measure.

The following table presents a summary of the changes in our estimated proved reserves which occurred during the year ended December 31, 2017.

	Total (MBoe)
Proved reserves at December 31, 2016		53,757
Revisions of previous estimates		2,130
Extensions and discoveries		7,597
Production		(9,885	)
Proved reserves at December 31, 2017		53,599

Revisions of previous estimates. For the year ended December 31, 2017, we made revisions of 2,130 MBoe, primarily attributable to a positive revision of approximately 3,800 MBoe due to upward proved developed producing performances in several fields. These positive revisions were primarily offset by negative revisions of approximately 2,000 MBoe due to three non-core primarily gas fields located in western Gulf of Mexico impacted by low natural gas prices during the year ended December 31, 2017.

Extensions and discoveries. For the year ended December 31, 2017, extensions and discoveries contributed 7,597 MBoe to the increase of our proved reserves primarily as a result of development well work, drilling of

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proven acreage and new proved undeveloped locations that were added. During the year ended December 31, 2017, extensions and discoveries primarily related to proved reserve additions in the Brutus and Glider fields and in the Main Pass 280 field totaling 5,457 MBoe and 1,157 MBoe, respectively.

The following table presents a summary of the changes in our estimated proved undeveloped reserves which occurred during the year ended December 31, 2017:

	Oil (MBbls)			Natural Gas (MMcf)			NGLs (MBbls)			Total (MBoe)
Proved undeveloped reserves at December 31, 2016		8,461			15,165			113			11,101
Revisions of previous estimates		622			(4,498	)		91			(37	)
Extensions and discoveries		3,766			6,091			213			4,994
Conversions to proved developed reserves		(1,182	)		(1,372	)		(32	)		(1,442	)
Proved undeveloped reserves at December 31, 2017		11,667			15,386			385			14,616

Revisions of previous estimates. During the year ended December 31, 2017, revisions of previous estimates were comprised of positive revisions, including 1,400 MBoe of positive revisions where new proved undeveloped reserves were converted from a previous proved developed case and a previous non-producing reserve case, 1,168 MBoe of positive revisions due to reserves that became economic and were concurrently included in our capital program, expected to be developed within five years, and 526 MBoe due to positive price movements. These positive revisions were offset by 2,081 MBoe of negative revisions due to proved undeveloped reserves reclassified to unproved reserves because they are no longer expected to be developed within five years of their initial recognition due to a shift in our capital program to larger scale projects and 977 MBoe of negative revisions due to various minor differences between the original Ryder Scott booking volumes and the current NSAI-generated volumes.

Extensions and discoveries. During the year ended December 31, 2017, extensions and discoveries were 4,994 MBoe due to additional offset locations associated with our drilling program primarily at the Glider and MP 280 fields.

Conversions to proved developed reserves. During the year ended December 31, 2017 we developed 15% of our proved undeveloped locations and 10% of our proved undeveloped reserves through the drilling and completion of two gross (1.67 net) development wells with total net capital costs of $14.8 million.

Estimation of Reserves

Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil, natural gas and NGLs that are recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. We have incremental

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probable reserves associated with each of the factors or booking categories described above. For example, at Brutus we booked probable reserves for areas (1) adjacent to proved reserves where our seismic data was less certain, (2) associated with reservoirs that are structurally higher than existing proved reserves and (3) associated with a greater percentage recovery of the hydrocarbons in place than assumed from proved reserves.

Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserve where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir. Possible reserves also include incremental quantities associated with a greater percentage of recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and we believe that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. We have incremental possible reserves associated with each of the factors or booking categories described above. For example, at Brutus we booked possible reserves for areas (1) adjacent to probable reserves as our seismic data was less certain, (2) associated with a greater percentage recovery of the hydrocarbons in place than assumed from possible reserves, (3) directly adjacent to portions of a reservoir that may be separated from proved areas by faults with displacement less than formation thickness and (4) that were structurally higher and lower than the proved areas. See “Risk Factors—Risks Related to Our Business—Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.”

For purposes of estimating our reserves, we, NSAI and Ryder Scott used technical and economic data including well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. Our reserves have been estimated using deterministic estimates. Standard engineering and geoscience methods were used, or a combination of methods, including performance analysis, volumetric analysis and analogy, which we, NSAI and Ryder Scott considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations subject to the exceptions discussed in this prospectus and the reserve reports. A substantial portion of these reserves are for undeveloped locations; such reserves are based on estimates of reserve volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results,

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including geologic interpretation, prices and future production rates and costs. See “Risk Factors—Risks Related to Our Business—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” appearing elsewhere in this prospectus.

Qualifications of Technical Persons and Internal Control over Reserves Estimation Process

Estimates of our oil and natural gas reserves relating to our fields as of July 31, 2018 and December 31, 2017 were based upon the reserve reports prepared by NSAI, an independent petroleum engineering firm, which estimated 100% of our proved reserves as of July 31, 2018 and December 31, 2017. Estimates of our oil and natural gas reserves relating to our fields as of December 31, 2016 were based upon the reserve reports prepared by NSAI and Ryder Scott, both of which reports combined estimated 100% of our proved reserves as of December 31, 2016. The NSAI and Ryder Scott reserve reports were prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers and the guidelines established by the SEC. However, Ryder Scott asserts two PUD cases included in the December 31, 2016 reserve estimates extend beyond the SEC rules in regard to being developed within five years of initially being recognized. These PUD cases were recognized by EnVen after formation of the Company in 2014. The technical personnel responsible for preparing the reserve estimates of NSAI and Ryder Scott meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI or Ryder Scott does not own an interest in our properties nor is employed on a contingent fee basis.

Our internal staff of petroleum engineers and geoscience professionals work closely with NSAI and Ryder Scott to ensure the integrity, accuracy and timeliness of data furnished to NSAI or Ryder Scott for use in their reserves estimation process. Throughout each fiscal year, our technical team meets with our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the reserves estimates. We provide historical information to independent reserve engineers for our properties such as ownership interest, oil, natural gas, and NGL production, well test data, commodity prices and operating and development costs. The NSAI reserve reports and Ryder Scott reserve report are reviewed with a representative of our internal technical staff before dissemination of the information.

Our Vice President of Engineering, Kendall Meyers, oversees the preparation of our reserve estimates. He has over 30 years of technical experience in petroleum engineering and reservoir evaluation and analysis. Mr. Meyers graduated from Louisiana State University with a Bachelor’s of Science Degree in Petroleum Engineering. The Society of Petroleum Engineers recognized Mr. Meyers’ achievements in 2009 and awarded him the Distinguished Contribution Award for Reservoir Description and Dynamics.

The preparation of our reserve estimates are completed in accordance with our internal control procedures, which are intended to ensure reliability of reserve estimations. These procedures, include, but are not limited to, the following:

• the review and verification of our actual historical production data by our internal technical staff, which we provide to the independent reserve engineers;

• the review by our Vice President of Engineering of our reserves estimates, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

• annual review of our year-ended reserves estimates by the board of directors, including the review of significant changes and all new proved undeveloped reserves additions;

• direct reporting responsibilities by our Vice President of Engineering to our President; and

• the verification of property ownership by our land department.

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Oil, Natural Gas, and NGL Prices and Production

The prices we receive for our oil, natural gas, and NGL production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas, and NGL are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. For a list of factors that could impact the realized prices of our oil, natural gas, and NGL production, see “Risk Factors—Risks Related to Our Business—Oil, natural gas, and NGL prices are volatile and further declines in prices or an extended period of depressed prices will materially adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

The following table presents the NYMEX WTI and NYMEX HH average prices, our average realized oil and natural gas prices (excluding and including effects of derivatives), our average realized oil and natural gas price differentials (excluding and including effects of derivatives) to the benchmark prices, and our average realized NGL price for the periods indicated:

	Six months ended June 30,						Year ended December 31,
	2018			2017(1)			2017(1)			2016(1)
Oil (per Bbl):
NYMEX WTI Average	$	65.46		$	49.95		$	50.85		$	43.47
Average realized price (excluding effects of derivatives)	$	65.19		$	46.30		$	48.66		$	37.18
Average realized price differential to benchmark(2)	$	(0.27	)	$	(3.65	)	$	(2.19	)	$	(6.29	)
Percentage of average realized price to benchmark(2)		99.6	%		92.7	%		95.7	%		85.5	%
Average realized price (including effects of derivatives)(3)	$	61.86		$	50.06		$	50.67		$	37.68
Natural gas:
NYMEX HH Average ($/MMBtu)	$	2.84		$	3.10		$	3.02		$	2.55
Average realized price (excluding effects of derivatives) ($/Mcf)	$	3.64		$	2.92		$	2.93		$	2.12
Average realized price differential to benchmark ($/Mcf)(2)(4)	$	0.69		$	(0.29	)	$	(0.20	)	$	(0.52	)
Percentage of average realized price to benchmark(2)(4)		123.6	%		90.8	%		93.6	%		80.3	%
Average realized price (including effects of derivatives) ($/Mcf)(3)	$	3.66		$	3.04		$	3.15		$	2.18
NGLs (per Bbl):
Average realized price	$	28.94		$	16.75		$	18.22		$	13.31

(1) The average realized prices (including and excluding derivatives) for the six months ended June 30, 2017 and the years ended December 31, 2017 and 2016 have not been adjusted to reflect the adoption of ASC 606 and include transportation, gathering, and processing costs as a reduction to oil, natural gas, and NGL revenues.

(2) Benchmarks are the NYMEX WTI and NYMEX HH average prices for oil and natural gas, respectively.

(3) The effects of derivatives represents, as applicable to the periods presented: (i) current period derivative settlements; (ii) the exclusion of the impact of current period settlements for early-terminated derivatives originally designated to settle against future production period revenues; (iii) the exclusion of option premiums paid in current periods related to future production period revenues; (iv) the impact of the prior period settlements of early-terminated derivatives originally designated to settle against future production period revenues; and (v) the impact of option premiums paid in prior periods related to current period production revenues.

(4) Calculated using a conversion factor of one Mcf equal to 1.037 MMBtu.

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The following table presents our total production by product and our average daily production volumes, average realized prices, and production costs per Boe for our fields that made up 15% or more of our proved reserve value as of December 31, 2017 for the periods indicated:

	Six months ended June 30,				Year Ended December 31,
	2018		2017		2017		2016(1)
Production volumes:
Oil (MBbls)		4,173		4,086		7,865		4,636
Natural gas (MMcf)		6,198		5,502		10,316		9,243
NGLs (MBbls)		127		145		301		279
Total (MBoe)		5,333		5,147		9,885		6,455
Average daily production (MBoe/d)		29.5		28.4		27.1		17.7
Brutus field
Production volumes:
Oil (MBbls)		1,213		502		1,138		4
Natural gas (MMcf)		2,178		427		909		3
Total (MBoe)		1,576		573		1,290		5
Average daily production (MBoe/d)		8.7		3.2		3.5		4.6
Average realized price:
Oil (per Bbl)	$	67.52	$	44.46	$	47.89	$	46.90
Natural gas (per Mcf)	$	3.98	$	2.46	$	3.03	$	3.70
Production cost per Boe	$	11.98	$	33.27	$	24.87	$	34.78
Glider field
Production volumes:
Oil (MBbls)		1,007		1,467		2,653		9
Natural gas (MMcf)		797		1,049		1,838		6
Total (MBoe)		1,139		1,642		2,959		10
Average daily production (MBoe/d)		6.3		9.1		8.1		10.0
Average realized price:
Oil (per Bbl)	$	63.75	$	45.33	$	47.20	$	46.90
Natural gas (per Mcf)	$	4.20	$	3.85	$	3.80	$	3.70
Production cost per Boe	$	0.61	$	0.02	$	0.06	$	0.20

(1) The Brutus and Glider fields were acquired on December 30, 2016, therefore, the year ended December 31, 2016 information only includes one day of production, sales, and costs.

Our oil production price has a premium or deduct differential to the prevailing NYMEX WTI price. A substantial portion of our crude differential reflects adjustments for location, crude quality, and transportation and gathering costs. Similar to oil, our natural gas production price has a premium or deduct differential to the prevailing NYMEX HH price primarily due to differential adjustments for location and quality and energy content of the natural gas. Location differentials result from variances in natural gas transportation costs based on the proximity of the natural gas to its major consuming markets that correspond with the ultimate delivery point as well as individual supply and demand dynamics. The majority of our natural gas production is delivered to a natural gas processor who gathers and processes our raw natural gas and remits proceeds for the resulting sales of NGLs and residue gas. NGL sales occur at the tailgate of the facility with prices derived from the Mont Belvieu Trading Hub. For a further discussion on our average realized prices, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Known Trends and Uncertainties—Realized Prices on the Sale of Oil, Natural Gas, and NGLs.”

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To reduce our price volatility, we may enter into derivative contracts to economically hedge a significant portion of our estimated production from our proved developed producing oil and natural gas properties against adverse fluctuations in commodity prices. By doing so, we believe we can mitigate, but not eliminate, the potential negative effects of decreases in oil and natural gas prices on our cash flows from operations. However, our hedging activity could reduce our ability to benefit from increases in oil and natural gas prices. We could sustain losses to the extent our derivative contract prices are lower than market prices and, conversely, we could recognize gains to the extent our derivative contract prices are higher than market prices. See “Risk Factors—Risks Related to Our Business—Our derivative activities could result in financial losses or could reduce our earnings”, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” for a discussion of historical commodity pricing.

Marketing and Customers

The marketability of our oil, natural gas, and NGL production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our share of oil, natural gas, and NGL production from our properties is sold under a series of arm’s length contracts awarded on a competitive bid basis or entered into following negotiations. Oil is sold directly to companies with refineries in the U.S. Gulf Coast regions of Texas and Louisiana at prices based on widely-used industry benchmarks. Gas is processed in one of nine large onshore gas plants, where we are paid our contractual share of revenues from the sale of natural gas. We sell our residue gas to a purchaser who delivers to various industrial and energy markets as well as intrastate and interstate pipeline systems.

We typically sell our production to a relatively small number of customers, as is customary in the exploration, development, and production business. Historically, we have sold a large portion of our oil production to Shell, see “Notes to Unaudited Condensed Consolidated Financial Statements—Note 14—Related Party Transactions” for a further discussion of our relationship with Shell as of and for the six months ended June 30, 2018.

During the six months ended June 30, 2018 and the year ended December 31, 2017, sales to Shell accounted for approximately 87% and approximately 85%, respectively, of our total revenue and they were the only purchaser which accounted for more than 10% of our total revenue. For the year ended December 31, 2016, sales to Shell accounted for approximately 69% of our total revenue and sales to Chevron Products Company accounted for approximately 11% of our total revenue. These were the only purchasers which accounted for more than 10% of our total revenue.

Competition

We encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of properties, marketing our oil, natural gas, and NGL production, and securing personnel. Many of our competitors are larger companies that have been engaged in the oil and natural gas business for longer than we have and possess substantially larger technical and personnel resources. They may also have greater capital resources than we do or can obtain access to capital resources at a lower cost than available to us. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, raising additional capital and attracting and retaining quality personnel, which could have a material adverse effect on our business, financial condition and results of operations.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations.

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Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities, some of which are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Regulation of Drilling and Production

Our drilling and production operations are subject to various types of regulation at the federal, state, and local level, which require, among other things, permits for the drilling of wells, drilling bonds, and reports concerning operations. BOEM and BSEE are our primary regulators. The state, as well as some counties parishes in Louisiana and municipalities, in which we operate also regulate the location of wells; the method of drilling and casing wells; the timing of construction or drilling activities, including seasonal wildlife closures; the rates of production or “allowables”; the surface use and restoration of properties upon which wells are drilled; the P&A of wells, and the disposal of fluids used in connection with operations.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. BOEM, BSEE and other federal regulators also have regulations affecting our operations on these and similar issues.

The BOEM and the BSEE approve and grant permits in connection with our exploration, drilling, development and production plans in federal waters. Delays in the approval or refusal of those plans or the issuance of permits by them could adversely affect our operations. Additionally, the BOEM/BSEE implement regulations which require offshore production facilities to meet stringent engineering, construction, safety and environmental specifications. These regulations could increase our costs or require us to update or retrofit our equipment, and may terminate, delay or suspend our operations. The BOEM/BSEE have adopted regulations providing for enforcement actions, including civil penalties and lease forfeiture or cancellation for failure to comply with regulatory requirements for offshore operations. Under certain circumstances, the BOEM/BSEE may suspend or terminate any of our operations on federal leases.

Regulation of Sales and Transportation of Oil and NGLs

Sales of oil and NGLs or condensate are not currently regulated and are made at market prices. Nevertheless, U.S. Congress could reenact price controls in the future.

The price we receive for our production is affected by the availability, terms and cost of transportation. The transportation of oil, NGLS and condensate is also subject to rate and access. The FERC regulates interstate oil and NGL pipeline transportation rates under the Interstate Commerce Act and EPA. In general, pipeline rates must be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. As effective interstate and intrastate rates are generally equally applicable to all comparable shippers, we believe that the regulation of oil and NGL transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

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Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis and must offer service to all similar situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future.

Regulation of Sales and Transportation of Natural Gas

Federal legislation and regulatory controls have historically affected the price of natural gas we produce and the manner in which our production is transported and marketed. Under the NGA, the FERC regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of natural gas, including all of our sales of our own production. As a result, all of our produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in effect. The FERC’s jurisdiction over interstate natural gas transportation, however, was not affected by the Decontrol Act.

Under the NGA, facilities used in the production or gathering of natural gas are exempt from the FERC’s jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.

Environmental Regulations and Worker Health and Safety

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) imposes joint and several liability, without regard to fault or legality of the conduct, on classes of persons who are considered to be responsible for the release of hazardous substances into the environment. These persons include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be liable for costs of investigation and cleaning up the hazardous substances that have been released into the environment, and for damages to natural resources. CERCLA also authorizes the EPA and third parties to take actions in response to threats to public health or the environment and to seek to recover the costs of such action.

Although CERCLA generally exempts “petroleum” from regulation, in the course of our operations, we may and could generate wastes that may fall within CERCLA’s definition of hazardous substances and may have disposed of these wastes at disposal sites owned and operated by others.

Many states have adopted comparable or more stringent state statutes but not all analogous state statutes provide similar exemptions.

Non-hazardous and hazardous wastes. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of non-hazardous and hazardous wastes. Oil and natural gas drilling and production waste is currently regulated as non-hazardous waste under RCRA. However, it is possible that certain oil and natural gas drilling and production waste now classified as non-hazardous waste could be categorized as hazardous waste in the future.

In December 2016, in order to resolve a lawsuit filed by several environmental group, the EPA entered into a consent decree in which it is required to propose, no later than March 15, 2019, a rulemaking for revision of certain criteria regulations pertaining to oil and natural gas wastes or sign a determination that any revision of the

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regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations it must take final action following notice and comment rulemaking no later than July 15, 2021. Any change to waste disposal regulations could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

Water discharges. The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into regulated waters. The discharge of pollutants into waters of the U.S. is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The OPA amends the CWA and imposes certain duties and liabilities on the owner or operator of a facility, vessel or pipeline that is a source or that poses the substantial threat of an oil discharge, or the lessee or permittee of the area in which a discharging offshore facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.

The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. The OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating in the Outer Continental Shelf (“OCS”), although the Secretary of Interior may increase this amount up to $150 million in certain situations.

BOEM/BSEE regulations. The BOEM and the BSEE have regulations applicable to lessees in federal waters that require lessees to have substantial U.S. assets and net worth or post bonds or other acceptable financial assurance that the regulatory obligations will be met. As of June 30, 2018, we had surety bonds of approximately $700 million for these obligations.

In July 2016, BOEM issued a new NTL, which has not been implemented and is currently under review by BOEM. The NTL augments requirements for the posting of financial assurance by offshore lessees and discontinues the policy of supplemental bonding waivers. During the review period, BOEM has required incremental financial assurance or bonding for sole liability properties, with which we are currently in compliance. However, changes to the NTL, or any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements regarding financial assurances or otherwise adversely affecting our offshore activities, could result in increased costs and consequently have a material adverse effect on our business, financial condition and results of operations.

The April 20, 2010 fire and explosion aboard the Deepwater Horizon drilling rig and resulting oil spill from the Macondo well operated by a third-party in deepwater in the U.S. Gulf of Mexico resulted in a series of federal regulatory initiatives which addressed the direct impact of the incident and aim to prevent similar incidents in the future. The DOI, through the BOEM and the BSEE, has issued a variety of regulations and NTLs intended to impose additional safety, permitting, and certification requirements applicable to exploration, development, and production activities in the U.S. Gulf of Mexico. These regulatory initiatives effectively slowed down the pace of drilling and production operations in the U.S. Gulf of Mexico as adjustments were made in operating procedures, certification requirements, lead times for inspections, drilling applications, and permits, and exploration and production plan reviews, and as the federal agencies evolved into their present day bureaus.

In June 2013, the Workplace Safety Rule, which requires operators to develop and implement a comprehensive safety and environmental management systems (“SEMS”) program for oil and natural gas

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operations was amended to include additional safety requirements. Operator were required to have an independent SEMS program audit completed by June 2015, which we completed in advance of the deadline.

On April 17, 2015, BSEE published a proposed rule that would impose more stringent standards on BOPs. In April 2016, BSEE issued a final version of this rule effective July 2016, though some requirements of the rule have delayed compliance deadlines. In response to the March 2017 Executive Order and a subsequent executive order issued by President Trump in April 2017 focusing on offshore energy development, in May 2018, BSEE published a proposal to relax certain requirements of the July 2016 rule. The proposed rule is subject to a 60 day comment period and will also likely be subject to legal challenges.

Air emissions and climate change. The CAA and comparable state laws and regulations govern emissions of various air pollutants through the issuance of permits and other authorization requirements. Air emissions from some equipment used in our operations are potentially subject these regulations. These permits or authorizations may place restrictions upon our air emissions and may require us to install expensive pollution control equipment. The CAA imposes administrative, civil and criminal penalties, as well as injunctive relief, for failure to comply.

Since 2009, the EPA has been monitoring and regulating GHG emissions, including carbon dioxide and methane, from certain sources in the oil and natural gas sector due to their association with climate change. Most of our facilities are subject to the EPA’s GHG annual reporting requirements that cover offshore oil and natural gas production, processing, transmission, storage, and distribution facilities.

In August 2015, the EPA finalized the CPP, which set forth binding guidelines for GHG emissions from existing power plants, as well as Power Plant NSPS. The March 2017 Executive Order signed by President Trump directed the EPA to initiate a rulemaking to suspend, revise or rescind both the CPP and the Power Plant NSPS (as well as other regulations relating to the energy industry) as necessary to ensure consistency with the goals of energy independence, economic growth and cost-effective environmental regulation. On April 4, 2017, the EPA announced that it is initiating its review of the Power Plant NSPS and CPP. On August 21, 2018, the EPA proposed to replace the CPP in its entirety with the ACE Rule, which is aimed at reducing GHG emissions from fossil fueled fired power plants by improving their efficiency. The ACE Rule was published in the Federal Register on August 31, 2018 and the period for public comment extends to October 31, 2018. The outcome of these rulemakings is uncertain and likely to be subject to an extensive notice and comment process and litigation.

In June 2016, the EPA published the 2016 Standards for methane, identified as a potent GHG, and volatile organic compound emissions from certain new, modified and reconstructed equipment, processes and activities across the oil and natural gas sector. These rules include first-time standards to address emissions of methane from equipment and processes across the source category, fugitive emissions from well sites and compressors, and equipment leaks at natural gas processing plants. In accordance with the March 2017 Executive Order, the EPA has initiated a review of these standards, a process which is ongoing. In addition, in March 2018, the EPA announced amendments to two narrow provisions of the 2016 New Source Performance Standards including removing the requirement for completion of delayed repairs during unscheduled or emergency vent blowdowns under the fugitive emissions provisions. In September 2018, the EPA published proposed revisions to the 2016 Standards which, among other changes, would reduce the required frequency of monitoring surveys at well sites and compressor stations, increase time to complete repairs related to leaks and allow companies operating in certain states to follow state-level standards as an alternative to federal standards. The draft rule is subject to a 60-day comment period beginning from the date of publication in the Federal Register. The outcome of this rulemaking is uncertain.

On the international level, in December 2015, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France which prepared the Paris Agreement. This agreement set GHG emission reduction goals every five years beginning in 2020, however, it does not create any binding obligations for nations to limit their GHG emissions.

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The Paris Agreement was signed by the U.S. in April 2016 and entered into force in November 2016. On June 1, 2017, President Trump announced that the U.S. plans to withdraw from the Paris Agreement and will seek negotiations to either re-enter the Paris Agreement under different terms or to establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020 for the U.S. The U.S.’ adherence to the exit process and/or the terms on which the U.S. may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs, or limit emissions of GHGs from our equipment and operations or those that transport, process or store our products, could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as cause delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for our products.

Endangered and threatened species. The Endangered Species Act was established to protect endangered and threatened species. If a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act, and marine mammals under the Marine Mammal Protection Act. A protected habitat designation could result in material restrictions to our use of our leases and may materially delay or prohibit development of our leases. The identification or designation of previously unprotected species as threatened or endangered in areas where our operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations or prohibitions on our exploration and production activities and could have an adverse impact on our ability to develop and produce reserves.

Worker health and safety. We are subject to the requirements of the federal Occupational Safety and Health Association (“OSHA”) and comparable state statutes and rules that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA emergency planning and community-right-to-know regulations, and similar state statutes and rules require that we maintain certain information about hazardous conditions or materials used or produced in our operations and that we provide this information to our employees, government authorities and citizens.

Environmental Compliance Matter

In early August 2018, in response to suggestions of potential noncompliance at our Cognac platform, we initiated an internal investigation of operations at Cognac led by outside counsel. This investigation concluded on September 28, 2018, and several allegations regarding noncompliance have been substantiated. First, in mid-March 2018, an EnVen employee improperly filtered a produced water sample taken to monitor compliance with the oil and grease effluent limitations in the applicable National Pollutant Discharge Elimination System (“NPDES”) general permit (the “Sample Filtering”). This employee took additional regulatory water samples from early 2015 through March 2018, some of which may also have been filtered. The investigation did not identify any other improper water sampling practices on Cognac, and there was no indication that similar filtering occurred at any other EnVen facilities. Second, the data resulting from the Sample Filtering was used to calculate an average relied upon in a quarterly report submitted by EnVen to the EPA (the “Inaccurate Reporting”). Data from the samples taken by this employee were used in other quarterly reports. Third, in mid-May 2018, three partially-full totes with the capacity to hold, in the aggregate, up to 830 gallons of water clarifier, a non-hazardous liquid used to remove solid waste particles from water, were improperly disposed overboard (the “Overboard Disposal”). While this Overboard Disposal is not in compliance with the Clean Water Act, we believe it did not trigger potentially applicable CERCLA or the Emergency Planning and Community Right-to-Know Act reporting requirements. Fourth, in mid-July 2018, a small fire on Cognac with an approximate one inch flame, which was started in connection with routine construction operations, was not timely reported to BSEE (the “Fire Incident”).

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We have made self-disclosures to the EPA regarding the Sample Filtering, the Inaccurate Reporting and the Overboard Disposal, and have formally reported the Fire Incident to the BSEE. The EPA is currently conducting an investigation based on our self-disclosures. We will continue to cooperate with the EPA in its investigation. We are uncertain at this time whether the EPA will pursue administrative, civil, or criminal penalties or injunctive relief, if any, against EnVen, nor are we certain what actions, if any, the BSEE may pursue. We are not able to definitively determine EnVen’s potential financial or other exposure related to these matters, nor the timing to fully resolve these matters. However, based on available information, we do not believe that any financial penalties associated with these matters will be material to EnVen and we do not believe that EnVen’s overall operating activities will be materially impacted. We expect to record a contingent liability of $2 million for the three months ended September 30, 2018 in connection with these matters. However, we may be required to record additional liabilities and expenses associated with these matters in future periods. Remedial actions are being implemented as a result of these matters, including a full environmental and BSEE compliance audit of Cognac, additional training of personnel on all of our facilities, the termination of certain employees, and the removal of certain contractors from the platform.

Operational Hazards and Insurance

The oil and natural gas industry involves a variety of operating risks, including the risk of fire, explosions, blowouts, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We have insurance policies for property (including leased oil and natural gas properties), general liability, operational control of certain wells, pollution, commercial auto, umbrella liability, inland marine, workers’ compensation and other coverage. We are self-insured for named windstorms in the Gulf of Mexico. We also have surety bonds associated with environmental and asset retirement obligations, self-insurance bonds for workers’ compensation claims and other bonds to cover additional liabilities.

Most of our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial condition. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Generally, we also require our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

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Employees

As of June 30, 2018, we had 140 full-time employees, of which 15 have technical experience and training to evaluate oil and natural gas assets and opportunities in the U.S. Gulf of Mexico. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full-time employees. We consider our relations with our employees to be satisfactory.

Legal Proceedings

From time to time, we are a party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims, employment-related disputes, commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. We do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations and liquidity.

Additional Company Information

Our corporate headquarters are located at 333 Clay Street, Suite 4200, Houston, TX 77002. We have additional offices in New Orleans, Louisiana and Lafayette, Louisiana.

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MANAGEMENT

Executive Officers and Directors

The following table provides information regarding our executive officers and our board of directors as of June 30, 2018:

Name	Age		Position
Steven A. Weyel		63	Chief Executive Officer and Chairman of the Board of Directors
David M. Dunwoody, Jr.		34	President
David A. Carmony		57	Chief Operating Officer
John P. Wilkirson		60	Chief Financial Officer and Executive Vice President
Jeffrey A. Starzec		41	Executive Vice President, General Counsel and Secretary
Kayla D. Baird		47	Vice President, Controller and Chief Accounting Officer
Jon A. Jeppesen		70	Director
Kenneth R. Olive, Jr.		65	Director
Richard Sherrill		52	Director
Andrew Hailey		32	Director
John Ezekowitz		27	Director
Christopher Linneman		58	Director

Directors and Executive Officers

Steven A. Weyel has served as our Chief Executive Officer and Chairman since 2015. Mr. Weyel was also a member of the Board of Directors of Energy Ventures GoM Holdings, LLC, our predecessor from July 2014 until November 2015. Previously, Mr. Weyel served as Chief Executive Officer of EnVen Energy Ventures, LLC since January 2013. Mr. Weyel is the founder and current Chairman of Equigen, LLC, an equity investment company focused on emerging market energy infrastructure and services. Until 2016, Mr. Weyel served on the Board of Directors of Rooster Energy Ltd., an integrated oil and natural gas company with an exploration and production business and a division which is a leading downhole and subsea well intervention and plugging and abandonment service provider. Mr. Weyel also formerly served as a director of Bahamas Petroleum Company PLC (AIM: “BPC”) from July 2011 through August 2014. Mr. Weyel co-founded and served as President, Chief Operating Officer and Director of Energy XXI (Bermuda) Limited (NASDAQ: EXXI) from its inception in October 2005 until August 2010. Mr. Weyel co-founded and served as a Principal, President and Chief Operating Officer of EnerVen LLC, a developer and supporter of strategic ventures in the emerging energy industry. From 1999 to 2002, Mr. Weyel served as President, Chief Operating Officer and Director of InterGen North America, a Shell-Bechtel joint venture that developed and operated large-scale independent power projects and managed gas pipelines, gas storage and associated energy commodity transactions in the merchant gas and power business. From 1994 to 1999, Mr. Weyel served in various executive leadership positions at Dynegy, Inc. including Executive Vice President—Integrated Energy and Senior Vice President—Power Development. Mr. Weyel currently serves on the Board of Directors of National Ocean Industries Association. Mr. Weyel has over forty years of entrepreneurial growth and operating experience in the energy industry, and his experience includes billions of dollars of energy related transactions and financings. Mr. Weyel earned a Master’s degree in Business Administration from the University of Texas at Austin and a Bachelor of Science in Industrial Distribution from Texas A&M University College of Engineering. We believe that Mr. Weyel is well qualified to serve as the Chairman of our board of directors given his extensive public company experience in the energy sector and background, including serving as a member of management since inception.

David M. Dunwoody, Jr. has served as our President since 2015. Mr. Dunwoody was also a member of the Board of Directors of Energy Ventures GoM Holdings, LLC, our predecessor from July 2014 to November 2015. Previously, Mr. Dunwoody served as President of EnVen Energy Ventures LLC since March 2013. From 2007 to 2013, Mr. Dunwoody served in various capacities for Apache Corporation’s U.S. Gulf of Mexico business unit,

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covering drilling, completion and production operations, corporate reserves, acquisitions, and reservoir engineering. He and his team, who currently serve in leadership positions of EnVen, were directly responsible for the discovery of reserves and value creation that competed with Apache’s global exploration and production portfolio. Mr. Dunwoody received his Bachelor of Science degree in Petroleum Engineering and a Master of Business Administration from the University of Texas at Austin.

David A. Carmony has served as our Chief Operating Officer since 2014. Mr. Carmony joined EnVen Energy Ventures LLC in 2014 as Chief Operating Officer after serving for three years as Vice President of Operations for Castex Energy’s U.S. Gulf of Mexico and Louisiana inland water operations. Mr. Carmony previously served as Vice President of Operations for the U.S. Gulf of Mexico and Gulf Coast regions at Apache Corporation. From 1993 to 2011, he also served in executive and engineering management positions while at Apache Corporation. Mr. Carmony held drilling, production and reservoir engineering positions with Pacific Enterprises Oil Company, formerly Terra Resources, from 1987 to 1992, and Mitchell Energy from 1983 to 1987. Mr. Carmony received his bachelor’s degree in petroleum engineering from the University of Oklahoma. He is a member of the following organizations: Society of Petroleum Engineers, American Association of Drilling Engineers and the Texas Independent Producers and Royalty Owners Association.

John P. Wilkirson has served as our Chief Financial Officer and Executive Vice President since 2016. Mr. Wilkirson was also a member of our board from January 2016 to December 2016. Mr. Wilkirson has over 35 years of experience in the energy industry. Mr. Wilkirson was Executive Vice President and Chief Financial Officer of Cobalt International Energy, an oil and gas exploration and development company with deepwater assets in the U.S. Gulf of Mexico, Angola and Gabon; a position he held from June 2010 until September 2015. From 2006 until June 2010, Mr. Wilkirson served Cobalt as a strategic advisor, Vice President of Strategic Planning and Investor Relations and interim Chief Financial Officer. Prior to joining Cobalt, from 1998 to 2005, Mr. Wilkirson was Vice President, Strategic Planning and Economics of Unocal Corporation, where his primary responsibilities included identifying and addressing major strategic issues, managing the global asset and investment portfolio, leading the economic analysis and evaluations function and overseeing performance management. He played an instrumental role as the integration executive for Unocal Corporation’s merger into Chevron Corporation. Prior to Unocal Corporation, from 1992 to 1997, Mr. Wilkirson was an Engagement Manager at McKinsey & Company, Inc., a management consulting firm, serving energy clients on strategy and performance improvement engagements. Additional industry experience includes positions at Exxon Company USA from 1980 to 1984 and Sohio Petroleum Company and BP from 1984 to 1991, in petroleum engineering and commercial assignments. Additionally, he has served as a member of the Board of Directors for the Sam Houston Area Council of the Boy Scouts of America and of the Board of Trustees for the Houston Museum of Natural Science. Mr. Wilkirson has a Bachelor of Science with Highest Honors in Petroleum Engineering and a Master of Business Administration from the University of Texas at Austin.

Jeffrey A. Starzec has served as our Executive Vice President, General Counsel and Secretary since 2018. Previously, Mr. Starzec was Executive Vice President, General Counsel and Secretary of Cobalt International Energy from February 2015 to April 2018. Prior to that, Mr. Starzec was Senior Vice President and General Counsel of Cobalt from January 2012 to February 2015 and Associate General Counsel and Corporate Secretary from June 2009 until December 2011. On December 14, 2017, Cobalt filed a voluntary petition under Chapter 11 of the U.S. Bankruptcy Code. Prior to joining Cobalt, Mr. Starzec practiced corporate and securities law at Vinson & Elkins LLP from 2006 until 2009, where he represented a variety of energy companies, including Cobalt in connection with its strategic alliance with Total in the U.S. Gulf of Mexico. Mr. Starzec began his legal career at Baker Botts LLP and holds a Bachelor of Science in Economics from Duke University and a J.D. from Harvard Law School.

Kayla D. Baird has served as our Vice President, Controller and Chief Accounting Officer since 2017. Mrs. Baird was Chief Accounting Officer for Permian Resources, LLC from September 2014 until August 2017. Prior to Permian Resources, LLC, she served in various executive positions at ConocoPhillips, including Director of Lower 48 Strategy & Portfolio Management and Reserves Reporting & Compliance; Manager of Commercial

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Gas, Crude & NGL; and Manager of Upstream & Corporate Accounting Policy. Mrs. Baird has 20 years of experience in the oil & gas industry. Previously, she worked for 13 years in public accounting, primarily for Ernst & Young, LLP, auditing large public oil and gas companies. Mrs. Baird holds a Bachelor of Science Degree in Accounting from Langston University and is a Certified Public Accountant.

Jon A. Jeppesen has served as a director since 2015. Mr. Jeppesen was Executive Vice President of Gulf Coast Region at Apache Corp. from August 2009 until his departure in 2014. Mr. Jeppesen served as a Senior Vice President of Apache Corp. from February 2003 until August 2009. Mr. Jeppesen served as Regional Vice President for the Gulf Coast region from 2002 until February 2003 and Regional Vice President of the Offshore region from 1996 until 2002. Mr. Jeppesen served as Vice President of Exploration and Development for North America of Apache from 1994 to 1996, and Manager of Offshore Exploration and Development from 1993 to 1994. Prior to Apache Corp., Mr. Jeppesen served as Vice President of Exploration and Development for Pacific Enterprises Oil Company, Dallas, Texas, from 1989 to 1992. He is a Member of the American Association of Petroleum Geologists and the Houston Geological Society. Mr. Jeppesen received his Bachelor’s and Master’s Degrees in Geology from Kansas State University. We believe that Mr. Jeppesen is well qualified to serve as a member of our board of directors given his experience in the offshore drilling industry and scientific background.

Kenneth R. Olive, Jr. has served a director since 2015. Mr. Olive was the President, the Chief Executive Officer and a member of the Board of Directors of The Oil & Gas Asset Clearinghouse (the “Clearinghouse”), an SEC registered Broker-Dealer, from his founding of the company in 1993 until April 2015. Under his guidance and oversight, The Clearinghouse established itself as an industry leading acquisition and divestiture advisor of oil and natural gas assets; closing over 31,000 transactions totaling approximately $11 billion. The Clearinghouse was the only A&D Advisory firm in the industry that offered a full spectrum of marketing techniques including: (1) live and internet “hybrid” auction services, (2) online auction services, (3) Mid-Value Negotiated services and (4) customized Negotiated Transaction services. All marketing services were fully supported technically by a team of more than 50 engineers, geoscientists, land personnel and technicians. Mr. Olive is a member of numerous industry professional associations. He has served on the board of Petroleum Place (an oil and natural gas upstream back office software provider), the Houston Association of Professional Landmen (“HAPL”), the Independent Petroleum Association of America’s South East Region board and the board of Support-a-Soldier which is a 501(c)3 charitable organization. Mr. Olive’s career began in 1968 in the oil fields of North Texas and South Louisiana working as a roustabout and rig hand. Following graduation from college, he served in a variety of staff, managerial and executive land and administrative positions gaining extensive experience in the U.S. Gulf of Mexico, Gulf Coast onshore, Permian Basin and Rocky Mountain regions of the U.S., including some International exposure. He was selected in 1997 as the Entrepreneur of the Year in the category of Energy and Energy Services by the Ernst and Young’s Entrepreneur program. He has also been named Outstanding Landman by HAPL and received the APEX award from the American Association of Professional Landmen for professional excellence and his entrepreneurial spirit. Mr. Olive received his Bachelor of Business Administration degree from Texas Tech University in 1974. We believe that Mr. Olive is well qualified to serve as a member of our board of directors given his experience and background in the energy sector, particularly with respect to acquisition and divestiture of oil and gas assets.

Richard Sherrill has served as a director since 2015. Mr. Sherrill is the President, board member and one of the founding partners of Ceritas Energy. Ceritas is a midstream natural gas company backed by private equity firms Quantum Energy Partners and Energy Spectrum Partners. The company is focused on providing producers with midstream gathering and processing solutions in various onshore regions of the U.S. The company is currently investing from its third private equity raise in Ceritas Energy II following the divestitures of Ceritas Energy and Ute Energy. The management team has been together for over ten years since the founding of the company in early 2003. Prior to forming Ceritas, Mr. Sherrill spent over ten years in the early deregulation of the natural gas and power industries. At Duke Energy for over four years, Mr. Sherrill held various senior management roles which culminated in his position of Chief Operating Officer of Duke Energy North America. In this role he oversaw all of the North American commercial activities for the company in the deregulated natural gas and power space. Mr. Sherrill’s team was instrumental in the formation of the Intercontinental

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Exchange, Inc. (ICE) and partnered with Goldman Sachs and other industry partners to launch the electronic platform that has become the preeminent online commercial exchange. Prior to Duke, Mr. Sherrill began at the private partnership Natural Gas Clearinghouse which ultimately became Dynegy, Inc. He spent over six years in all phases of the treasury, physical trading, financial trading and business development areas of the company. Mr. Sherrill began his career out of college with over four years at First Interstate Bank of Texas, now Wells Fargo. In 2018, Mr. Sherrill joined the board of Castex Energy 2015 Holdco, LLC as an independent director. Mr. Sherrill earned a Bachelor of Business Administration degree in finance from the University of Texas at Austin. We believe that Mr. Sherrill is well qualified to serve as a member of our board of directors given his experience and background in the energy sector, particularly with respect to fast-growing energy companies.

Andrew Hailey has served as a director since April 2018. Mr. Hailey joined Bain Capital Credit in October 2014 where he covers investments in the Energy space. Previously, Mr. Hailey was a Vice President at Cadent Energy Partners, an energy-focused private equity firm, from December 2010 through September 2014. Prior to that, he worked as an investment banking analyst at Simmons & Company. Mr. Hailey received degrees in Business Honors and Plan II Honors at the University of Texas. We believe that Mr. Hailey is well qualified to serve as a member of our board of directors given his experience and background in evaluating investments in the energy sector.

John Ezekowitz has served as a director since 2016. Mr. Ezekowitz is a Vice President in Opportunistic Credit at Bain Capital. He joined Bain Capital in 2013, and prior to his current role, he was a member of the Industry Research team responsible for investments in the Oil and Gas sector. Mr. Ezekowitz worked as a basketball analytics consultant for the Phoenix Suns and received a Bachelor of Arts degree, magna cum laude, from Harvard College. We believe that Mr. Ezekowitz is well qualified to serve as a member of our board of directors given his experience and background in evaluating investments in the energy sector.

Christopher Linneman has served as a director since 2016. Mr. Linneman is a Managing Director and head of Bain Capital Credit’s New York office. He joined Bain Capital Credit in 2015. From 2009 through 2014, he was head of the JPMorgan Mezzanine investment business as part of the JPMorgan Global Special Opportunities Group, a multi-billion dollar private investment business. Between 1994 and 2000 he was a Managing Director in High Yield Capital Markets and in 2001 became Co-Head of Syndicated and Leveraged Finance at JPMorgan. Mr. Linneman has served on multiple private, public, for profit and not-for-profit boards of directors. Mr. Linneman received a JD/MBA from Columbia University and a Bachelor of Science and Engineering degree from Princeton University. We believe that Mr. Linneman is well qualified to serve as a member of our board of directors given his experience and background in the financial sector.

Board Composition and Election of Directors

Our board of directors currently consists of seven members. Prior to the date that our Class A common stock is first traded on the NYSE, we expect to have an              member board of directors.

In connection with this offering, we will enter into a shareholders agreement with the Bain Investors. Among other things, the shareholders agreement provides the Bain Investors with the right to nominate a certain number of directors in proportion to their ownership of our outstanding Class A common stock, so long as the Bain Investors own at least 10% of such outstanding shares. See “Certain Relationships and Related Party Transactions—Shareholders Agreement” for additional information.

Our directors will be divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2019, 2020 and 2021, respectively.              and              will be assigned to Class I,              and              will be assigned to Class II, and              and              will be assigned to Class III. At each annual meeting of stockholders held after the initial classification, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a

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majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Our board has determined that each of                 ,                  and                  is independent under applicable NYSE rules.

Board Committees

Audit Committee

The members of our audit committee are              ,              and             .              is the chairman of our audit committee. The composition of our audit committee meets the requirements for independence under the current NYSE listing standards and pursuant to Rule 10A-3 of the Exchange Act. Each member of our audit committee is financially literate. In addition, our board of directors has determined that              is an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of Regulation S-K promulgated under the Securities Act. This designation does not impose on our audit committee financial expert any duties, obligations or liabilities that are greater than are generally imposed on members of our audit committee and our board of directors. Our audit committee is directly responsible for, among other things:

• selecting a firm to serve as the independent registered public accounting firm to audit our financial statements;

• ensuring the independence of the independent registered public accounting firm;

• discussing the scope and results of the audit with the independent registered public accounting firm and reviewing, with management and that firm, our interim and year-end operating results;

• establishing procedures for employees to anonymously submit concerns about questionable accounting or audit matters;

• considering the adequacy of our internal controls and internal audit function;

• reviewing material related party transactions or those that require disclosure; and

• approving or, as permitted, pre-approving all audit and non-audit services to be performed by the independent registered public accounting firm.

Compensation Committee

The members of our compensation committee are                 ,                  and                 .                  is the chairman of our compensation committee. Each member of this committee is a non-employee director, as defined by Rule 16b-3 promulgated under the Exchange Act, and an outside director, as defined pursuant to Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”), and meets the requirements for independence under the current NYSE listing standards and SEC rules and regulations. Our compensation committee is responsible for, among other things:

• reviewing and approving, or recommending that our board of directors approve, the compensation of our executive officers;

• reviewing and recommending to our board of directors the compensation of our directors;

• administering our stock and equity incentive plans;

• reviewing and approving, or making recommendations to our board of directors with respect to, incentive compensation and equity plans; and

• reviewing our overall compensation philosophy.

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Nominating and Governance Committee

The members of our nominating and governance committee are                 ,                  and                 .                  is the chairman of our nominating and governance committee.                  and                  meet the requirements for independence under the current NYSE listing standards. Our nominating and governance committee is responsible for, among other things:

• identifying and recommending candidates for membership on our board of directors;

• reviewing and recommending our corporate governance guidelines and policies;

• reviewing proposed waivers of the code of conduct for directors and executive officers;

• overseeing the process of evaluating the performance of our board of directors; and

• assisting our board of directors on corporate governance matters.

Code of Ethics

In connection with this offering, our board of directors will adopt a code of ethics that applies to all of our employees, officers and directors, including our President and Chief Executive Officer, Chief Financial Officer and other executive and senior financial officers. Upon completion of this offering, the full text of our codes of business conduct and ethics will be posted on the investor relations section of our website. We intend to disclose future amendments to our codes of business conduct and ethics, or any waivers of such code, on our website or in public filings.

Compensation Committee Interlocks and Insider Participation

None of our executive officers have served as a member of a compensation committee (or if no committee performs that function, the board of directors) of any other entity that has an executive officer serving as a member of our board of directors.

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EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth information concerning the compensation paid to our principal executive officer and our two other most highly compensated executive officers (our “named executive officers”) during our fiscal year ended December 31, 2017. For the fiscal year ended December 31, 2017, our named executive officers were Steven A. Weyel, our Chief Executive Officer and Chairman of the Board of Directors, David M. Dunwoody, Jr., our President, and John P. Wilkirson, our Chief Financial Officer and Executive Vice President. All numbers are rounded to the nearest dollar.

Name and Principal Position	Year		Salary ($)		Stock Awards ($)(1)		Non-Equity Incentive Plan Compensation ($)(2)		All Other Compensation ($)(3)		Total ($)
Steven A. Weyel Chief Executive Officer and Chairman of the Board of Directors		2017		750,000		3,326,834		1,406,250		76,993		5,560,077
David M. Dunwoody, Jr. President		2017		500,000		1,232,168		637,989		24,615		2,394,772
John P. Wilkirson Chief Financial Officer and Executive Vice President		2017		475,000		1,170,558		637,989		34,466		2,318,013

(1) The amounts in this column reflect the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. See “Notes to Audited Consolidated Financial Statements—Note 1—Organization and Summary of Significant Accounting Policies” and “Notes to Unaudited Condensed Consolidated Financial Statements—Note 10—Stock-based Compensation”. The amounts in this column assume that performance-based restricted stock units are earned at maximum.

(2) The amounts in this column reflect payments under our short-term incentive plan.

(3) The amounts in this column include the following for Mr. Weyel: $13,500 in matching contributions under our 401(k) plan, $36,141 in Company-paid life insurance premiums (which includes $15,161 in related tax gross up payments), $21,000 in Company-paid automobile allowances and $6,352 in Company-paid legal expenses (which includes $2,665 in related tax gross up payments).

The amounts in this column include the following for Mr. Dunwoody: $2,522 in Company-paid life insurance premiums (which includes $1,058 in related tax gross up payments), $6,460 in Company-paid tax advice expenses (which includes $2,710 in related tax gross up payments) and $15,633 in Company-paid legal expenses (which includes $6,558 in related tax gross up payments).

The amounts in this column include the following for Mr. Wilkirson: $13,500 in matching contributions under our 401(k) plan, $7,726 in Company-paid life insurance premiums (which includes $3,241 in related tax gross up payments) and $13,240 in Company-paid tax advice expenses (which includes $5,554 in related tax gross up payments).

Employment Agreements with Named Executive Officers

We have entered into employment agreements with each of our named executive officers. Certain of the material terms of these agreements are summarized below.

The employment agreement for Mr. Weyel has an initial term of three years, which term is automatically extended on a daily basis such that the remaining term for Mr. Weyel’s employment agreement is always three years. The employment agreements for Messrs. Dunwoody and Wilkirson have an initial term of three years,

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which term is automatically extended on an annual basis on the anniversary date of each of their employment agreements, such that the remaining term for each of their employment agreements is re-set to three years on each such anniversary. Pursuant to the employment agreements, each of our named executive officers receives an annual base salary and is eligible to participate in our bonus programs and plans (with an annual target bonus set at 150% of annual base salary for Mr. Weyel and at 100% of annual base salary for Messrs. Dunwoody and Wilkirson). In addition, our named executive officers are entitled to be reimbursed for the cost of obtaining legal, financial and tax advice and for premiums on maintaining one or more life insurance policies, and in each case are also entitled to a “gross up” payment for taxes on such reimbursements.

Each of the employment agreements provides for specified benefits on a qualifying termination of employment, including in connection with a “change in control”. On termination of employment due to death or disability, each of our named executive officers (or his estate) is entitled to receive the following payments and benefits: (a) an amount equal to his annual base salary, payable over 12 months, (b) a pro rata annual cash bonus for the year of termination, based on target performance, payable in one lump sum (c) reimbursement for group health plan premiums for up to 18 months for Messrs. Weyel and Dunwoody and for up to 12 months for Mr. Wilkirson (or, if applicable, for their eligible dependents), and (d) accelerated vesting of the portion of his unvested equity awards that would have vested on the next regularly scheduled vesting date (with performance goals deemed to have been achieved at maximum performance). On termination of employment by the Company without “cause” or the executive’s resignation for “good reason”, or following a termination of employment for any reason within two years following a “change in control”, each of our named executive officers is entitled to receive the following payments and benefits: for Mr. Weyel, (a) an amount equal to three times the sum of his annual base salary and target annual cash bonus, payable in 18 equal monthly installments, (b) a pro-rata annual cash bonus for the year of termination, based on target performance, payable in one lump sum (c) payment for senior executive health plan premiums for up to 36 months (or, if applicable, for his eligible dependents), (d) reimbursement for group health plan premiums for up to 18 months (or, if applicable, for his eligible dependents), and (e) accelerated vesting of all of his unvested equity awards (with performance goals deemed to have been achieved at maximum performance); for Mr. Dunwoody, (a) an amount equal to the number of complete calendar months remaining in the term, divided by 12, times the sum of his base salary and target annual cash bonus, payable in 12 equal monthly installments (b) a pro-rata annual cash bonus for the year of termination, based on target performance, payable in one lump sum (c) payment for senior executive health plan premiums for up to 18 months (in the case of a termination of employment by the Company without “cause” or a resignation for “good reason”) or 24 months (in the case of a termination for any reason within two years following a “change in control”) (or, if applicable, for his eligible dependents), (d) reimbursement for group health plan premiums for up to 18 months (or, if applicable, for his eligible dependents), and (e) accelerated vesting of all of his unvested equity awards (with performance goals deemed to have been achieved at maximum performance); and for Mr. Wilkirson, (a) an amount equal to the number of complete calendar months remaining in the term, divided by 12, times the sum of his base salary and target annual cash bonus, payable in 12 equal monthly installments (b) a pro-rata annual cash bonus for the year of termination, based on target performance, payable in one lump sum (c) reimbursement for group health plan premiums until he is no longer eligible for COBRA continuation coverage (or, if applicable, for his eligible dependents), and (d) accelerated vesting of all of his unvested equity awards (with performance goals deemed to have been achieved at maximum performance). On a termination of employment due to retirement, each of our named executive officers is entitled to receive accelerated vesting of all of his unvested equity awards (with performance goals deemed to have been achieved at maximum performance). Each of our named executive officers is also entitled to receive a “gross up” payment if any payment or benefit received under his employment agreement is subject to additional taxes or interest under Section 409A of the Code.

As used in the employment agreements, “cause” means the executive’s (a) gross negligence, or willful misconduct, (b) being convicted of a felony or any other crime that involves fraud or moral turpitude that results in a material adverse effect on the Company, (c) material breach of any material provision of the employment agreement, or (d) failure to follow any reasonable, material Company policy or direction of our board of directors. As used in the employment agreements, “good reason” means, without the executive’s written consent,

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(a) a material diminution of position, duties or authorities, (b) a failure by the Company to continue any plan in which the executive participates that is material to his total compensation (unless any such failure relates to a discontinuation of such plans or participation on a management-wide or Company-wide basis), (c) the taking of any action by the Company that would directly or indirectly materially reduce or deprive the executive of any material pension, welfare or fringe benefit (unless such action relates to a discontinuation of benefits on a management-wide or Company-wide basis), (d) the relocation of the Company’s headquarters or the Company requiring the executive to relocate anywhere outside of 10 miles of downtown Houston, Texas, or (e) the Company’s material breach of the employment agreement. For each of our named executive officers, entitlement to the payments and benefits described above (other than on account of termination due to death) is conditioned on his execution and non-revocation of a general release of claims and compliance with the restrictive covenants described below.

Under the employment agreements, our named executive officers are subject to the following restrictive covenants: (a) a perpetual confidentiality obligation, (b) a non-competition covenant during employment and for 12 months thereafter (which period, for Mr. Weyel, may be extended to 18 months depending on whether he receives severance payments in connection with a termination of employment by the Company without “cause” or in connection with a “change in control”), (c) a covenant on non-solicitation of Company executives during employment and for 12 months thereafter (which period, for Mr. Weyel, may be extended to 18 months depending on whether he receives severance payments in connection with a termination of employment by the Company without “cause” or in connection with a “change in control”), and (d) a non-disparagement obligation during employment.    

Each employment agreement provides that incentive-based compensation paid to our named executive officers is subject to any policy related to the claw-back of incentive-based compensation, or any similar policy, as required by law or in effect on the date that the particular incentive-based compensation is paid, awarded, or granted.

Outstanding Equity Awards at Fiscal Year End

The following table sets forth information regarding outstanding equity awards held by our named executive officers as of December 31, 2017.

	Option Awards								Stock Awards
Name	Number Of Securities Underlying Unexercised Options (#) Exercisable (1)		Number Of Securities Underlying Unexercised Options (#) Unexercisable (1)		Option Exercise Price ($)		Option Expiration Date		Number Of Shares Or Units Of Stock That Have Not Vested (#)(2)		Market Value Of Shares Or Units Of Stock That Have Not Vested ($)(3)		Equity Incentive Plan Awards: Number Of Unearned Shares, Units Or Other Rights That Have Not Vested (#)(4)		Equity Incentive Plan Awards: Market Or Payout Value Of Unearned Shares, Units Or Other Rights That Have Not Vested ($)(5)
Steven A. Weyel		158,893		79,446		10.00		11/05/2025		258,135		4,842,613		138,966		2,607,002
David M. Dunwoody, Jr.		105,929		52,964		10.00		11/05/2025		130,916		2,455,984		51,469		965,558
John P. Wilkirson		38,252		76,504		10.00		11/05/2025		163,652		3,070,112		48,896		917,289

(1) For Mr. Weyel and Mr. Dunwoody, reflects a grant of 238,339 and 158,893 stock options, respectively, which vest in three substantially equal installments on the first three anniversaries of November 6, 2015. For Mr. Wilkirson, reflects a grant of 114,756 stock options which vest in three substantially equal installments on the first three anniversaries of January 18, 2016.

(2) For Mr. Weyel, reflects grants of 238,339 shares of restricted stock which vest in two substantially equal installments on the second and third anniversaries of November 6, 2015 and 138,966 time-based restricted stock units which vest in two substantially equal installments on the second and third anniversaries of January 1, 2017. For Mr. Dunwoody, reflects grants of 158,893 shares of restricted stock which vest in two substantially equal installments on the second and third anniversaries of November 6, 2015 and 51,469 time-

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based restricted stock units which vest in two substantially equal installments on the second and third anniversaries of January 1, 2017. For Mr. Wilkirson, reflects grants of 114,756 shares of restricted stock which vest in two substantially equal installments on the second and third anniversaries of January 18, 2016 and 48,896 time-based restricted stock units which vest in two substantially equal installments on the second and third anniversaries of January 1, 2017.

(3) The market value of unvested restricted stock and time-based restricted stock units was calculated by multiplying the number of underlying award shares by $18.76, which was the fair market value of one share of our Class A common stock on December 31, 2017.

(4) Reflects grants of 138,966 performance-based restricted stock units for Mr. Weyel, 51,469 performance-based restricted stock units for Mr. Dunwoody, and 48,896 performance-based restricted stock units for Mr. Wilkirson, which will vest in a one-third portion upon each of the following specified events occurring before the fifth anniversary of January 1, 2017: a public listing of the Company’s shares, the Company’s average daily produced volume for a 365-day period equaling or exceeding 40,000 barrels, and adding 19 million oil equivalent barrels to the Company’s proved-developed-producing reserves.

(5) The market value of unvested performance-based restricted stock units was calculated by multiplying the number of underlying award shares by $18.76, which was the fair market value of one share of our Class A common stock on December 31, 2017.

Equity Incentive Compensation Plans

EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan

In 2015, our board of directors adopted, and our stockholders approved, the EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan (the “2015 Plan”). Certain of the material terms of the 2015 Plan are summarized below.

As of June 30, 2018, there were 682,650 stock options (of which 455,100 were exercisable) and 1,477,393 restricted stock units and restricted stock awards (both time-based and performance-based) outstanding under the 2015 Plan. As of June 30, 2018, 150,044 shares of our Class A common stock remained available for issuance under the 2015 Plan, which includes shares of Class A common stock that were forfeited, expired or settled in cash.

The 2015 Plan is administered by the Company’s Compensation Committee. The 2015 Plan allows for the issuance of stock options, which may be incentive stock options or nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, stock payments, performance shares, dividend equivalents, performance cash bonuses and other incentive awards covering shares of common stock. The 2015 Plan also allows for the issuance of management incentive units of EnVen GoM (with each unit counting as one share of common stock for purposes of calculating the number of shares available for awards), which are intended to constitute “profits interests”. The terms and conditions of awards under the 2015 Plan are set forth in award agreements and are subject to terms and conditions deemed appropriate by the Compensation Committee.

Eligibility; Limitation on Non-Employee Directors. Awards may be issued under the 2015 Plan to the Company’s employees, consultants and non-employee directors. No non-employee director may be granted awards having an aggregate grant date fair value in excess of $600,000 during a single fiscal year.

Shares Subject to the 2015 Plan. The aggregate number of shares of our common stock reserved for issuance under the 2015 Plan was 2,583,301. Shares subject to awards that are forfeited or expire, or with respect to awards that settle in cash, are available for future grants under the 2015 Plan.

Adjustments; Corporate Transactions. In the event of any stock dividend, stock split, combination or exchange of shares, merger, consolidation or other distribution (other than normal cash dividends) of Company assets to stockholders, or any other change affecting shares of the Company’s stock or the share price of the

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Company’s stock (other than an equity restructuring), the Compensation Committee may make equitable adjustments, if any, to reflect such change with respect to (a) the aggregate number and kind of shares that may be issued under the 2015 Plan, (b) the number and kind of shares (or other securities or property) subject to outstanding awards, (c) the terms and conditions of any outstanding awards (including, without limitation, any applicable performance targets or criteria with respect thereto) and/or (d) the grant or exercise price per share for any outstanding awards.

In the event of a corporate transaction described above or any unusual or nonrecurring transactions or events or changes in applicable law or applicable accounting standards, the Compensation Committee may in its sole discretion (a) provide for the termination of any award in exchange for an amount of cash and/or other property, if any, equal to the amount that would have been attained upon the exercise or realization of the participant rights, (b) provide that such award may be assumed by the successor or survivor corporation, or substituted for by similar awards (with appropriate adjustments as to the number and kind of shares and applicable exercise or purchase price, (c) adjust the number and type of securities subject to outstanding awards and awards that may be granted in the future and/or the terms, conditions and criteria of such awards, (d) provide that such awards shall be exercisable or payable or fully vested, notwithstanding anything in the 2015 Plan, a program thereunder or an award agreement to the contrary, (e) replace an award with other rights or property selected by the Compensation Committee in its sole discretion or (f) provide that an award cannot vest, be exercised or become payable after such event.

In connection with an equity restructuring, (a) the number and type of securities subject to each outstanding award and the exercise price or grant price thereof, if applicable, shall be equitably adjusted and/or (b) the Compensation Committee shall make such equitable adjustments, if any, as it deems appropriate with respect to the aggregate number and kind of shares that may be issued under the 2015 Plan.

Amendment and Termination. No awards may be granted under the 2015 Plan after the tenth anniversary of the date the 2015 Plan was first adopted by our board of directors, provided that any outstanding awards on such date will remain in force according to the terms of the 2015 Plan and the applicable award agreements. The 2015 Plan may be amended or otherwise modified, suspended or terminated at any time by our board of directors, provided that no amendment, suspension or termination shall impair any rights or obligations under any award therefore granted without the consent of the affected participant. The Compensation Committee may not increase the aggregate number of shares reserved for issuance under the 2015 Plan without the approval of the Company’s stockholders given within 12 months before or after such action.

Governing Law. The 2015 Plan is construed and enforced in accordance with the laws of the State of Delaware.    

Class B Incentive Units

Certain named executive officers and other employees have been issued profits interests designated as Class B units in EnVen Equity Holdings (the “Class B Incentive Units”). The Class B Incentive Units are subject to a multi-tier distribution waterfall and any potential payout will occur only after a specified level of cumulative distributions has been received by EIG Global Energy Partners and Sankaty Advisors and certain of our other owners, including members of our management team, in respect of their Class A interests in EnVen Equity Holdings. Although EnVen Equity Holdings will bear all costs of this incentive program, we account for the Class B Incentive Units as a profit sharing arrangement under ASC Topic 710, Compensation – General (“ASC 710”) as the costs will be incurred on behalf of us; therefore, we will record non-cash compensation expense when Class B Incentive Units distributions become probable. Consistent with SEC guidance, due to this accounting treatment, when distributions are made to our named executive officers, those amounts will be reported as “All Other Compensation” in the summary compensation table. As of June 30, 2018, there have been no distributions or probable distributions related to the Class B Incentive Units.

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Non-Equity Incentive Compensation Plans

Short-Term Incentive Program

Our named executive officers and certain other employees are eligible to participate in our short-term incentive program. Target bonuses are set as a percentage of base salary and are earned at between 0% and 200% of target depending on a combination of corporate and individual performance metrics, which are set annually by our board of directors.

Retirement Benefits

EnVen Energy Ventures LLC 401(k) Plan

Certain of our named executive officers and certain other employees participate in a 401(k) defined contribution plan sponsored by EnVen Energy Ventures LLC. Under the 401(k) plan, EnVen Energy Ventures LLC matches a participant’s contributions (including for certain of our named executive officers) at 100% of the first 5% of eligible compensation that is contributed to the plan. Participants are immediately vested in such matching contributions when made.

We do not provide a pension plan for employees and none of our named executive officers participates in a nonqualified deferred compensation plan.

Director Compensation

We believe that attracting and retaining qualified non-employee directors is critical to our future value growth and governance. Following the IPO, our non-employee directors are to receive: (a) an annual cash retainer of $60,000, (b) committee chairperson fees ranging from $10,000 to $15,000, (c) committee membership fees ranging from $7,500 to $10,000 and (d) an annual equity award with an approximate value of $120,000. Directors who are also our employees do not receive any additional compensation for their service on our board of directors. Each director is reimbursed for travel and miscellaneous expenses to attend meetings and activities of our board of directors or its committees.

The following table sets forth the compensation granted to our non-employee directors during the year ended December 31, 2017.

Name	Fees Earned Or Paid In Cash ($)(2)		Stock Awards ($)(3)		Total ($)
Jon A. Jeppesen		71,250		450,940		522,190
Kenneth R. Olive, Jr.		67,500		450,940		518,440
Richard Sherrill		80,000		450,940		530,940
Andrew Hailey(1)		180,000		—		180,000
John Ezekowitz(1)		180,000		—		180,000
Christopher Linneman(1)		180,000		—		180,000

(1) Fees were paid directly to Bain Capital.

(2) The amounts in this column reflect annual cash retainers and committee membership and chairperson fees paid in 2017. For Messrs. Hailey, Ezekowitz and Linneman, the amounts in this column also represent an additional cash payment of $120,000 in lieu of an annual equity award.

(3) While these amounts reflect all of the stock awards that were granted in 2017 (as required by the SEC rules), these stock awards were granted in order to comensate directors for services provided both in 2016 and 2017. Of this amount, approximately $120,000 was intended to compensate our directors for services provided in 2017. The amounts in this column reflect the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. See “Notes to Audited

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Consolidated Financial Statements—Note 1—Organization and Summary of Significant Accounting Policies” and “Notes to Unaudited Condensed Consolidated Financial Statements—Note 10—Stock-based Compensation”. The aggregate number of unvested time-based restricted stock units held by each director as of December 31, 2017 is as follows: Mr. Jeppesen, 20,000; Mr. Olive, 20,000; Mr. Sherrill, 20,000; Mr. Hailey, 0, Mr. Ezekowitz, 0; and Mr. Linneman, 0. For Messrs. Jeppesen, Olive and Sherrill, this column represents grants of 12,000 time-based restricted stock units which vested on June 14, 2017, 10,000 time-based restricted stock units which vested on January 1, 2018 and 10,000 time-based restricted stock units which vest on January 1, 2019.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

We describe below transactions and series of similar transactions, during our last three fiscal years or currently proposed, to which we were a party or will be a party, in which:

• the amounts involved exceeded or will exceed $120,000; and

• any of our directors, executive officers or beneficial holders of more than 5% of any class of our capital stock had or will have a direct or indirect material interest.

Other than as described below, there have not been, nor are there any currently proposed, transactions or series of similar transactions meeting this criteria to which we have been or will be a party other than compensation arrangements, which are described where required under “Management—Board Composition and Election of Directors” and “Executive Compensation.”

Tax Receivable Agreement

Pursuant to the terms of the EnVen GoM LLC Agreement, the members of EnVen GoM have the right to redeem the LLC Units for cash payment equal to the fair value of our Class A common stock, or at our option, for our Class A common stock. When a holder of LLC Units exercises such right to have its LLC Units redeemed or, at our election, exchanged, the redeeming holder will receive cash or shares of our Class A common stock, from which we may obtain an increase in our share of the tax basis of the assets of EnVen GoM. A Basis Adjustment may have the effect of reducing the amounts that we would otherwise pay in the future to various tax authorities. The Basis Adjustments may also decrease gains (or increase losses) on future dispositions of certain capital assets to the extent tax basis is allocated to those capital assets.

We are parties to the Tax Receivable Agreement with EnVen GoM and EnVen Equity Holdings for the benefit of the members of EnVen Equity Holdings. The Tax Receivable Agreement provides for the payment by us to such persons of 85% of the amount of tax benefits, if any, that we actually realize, or in some circumstances are deemed to realize, as a result of any Basis Adjustment or any other increases in the tax basis of the assets of EnVen GoM attributable to payments made under the Tax Receivable Agreement and deductions attributable to imputed interest and other payments of interest pursuant to the Tax Receivable Agreement. EnVen GoM will have in effect an election under Section 754 of the Code, effective for each taxable year in which a redemption or exchange of LLC Units for shares of our Class A common stock or cash occurs. These Tax Receivable Agreement payments are not conditioned upon any continued ownership interest in either EnVen GoM or us by EnVen Equity Holdings or members of EnVen Equity Holdings. The rights of EnVen Equity Holdings and its members under the Tax Receivable Agreement are assignable to transferees of its LLC Units (other than us as transferee pursuant to subsequent redemptions (or exchanges) of the transferred LLC Units). We will benefit from the remaining 15% of tax benefits, if any, that we may actually realize. The beneficiaries of the Tax Receivable Agreement includes the holders of more than 10% of the Class A LLC interests of EnVen Equity Holdings, being EIG Tarpon Holdings, LLC and Sankaty Credit Opportunities V AIV I, L.P., an affiliate of Bain, as well as certain members of management through their ownership of both Class A and Class B LLC interests of EnVen Equity Holdings.

The actual Basis Adjustments, as well as any amounts paid to EnVen Equity Holdings or its members under the Tax Receivable Agreement, vary depending on a number of factors, including:

• the timing of any subsequent redemptions or exchanges—for instance, the increase in any tax deductions will vary depending on the fair value, which may fluctuate over time, of the depreciable or amortizable assets of EnVen GoM at the time of each redemption or exchange;

• the price or fair market value, as applicable, of shares of our Class A common stock at the time of redemptions or exchanges—the Basis Adjustments, as well as any related increase in any tax deductions, are directly related to the price of shares of our Class A common stock at the time of each redemption or exchange;

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• the extent to which such redemptions or exchanges are taxable—if a redemption or exchange is not taxable for any reason, increased tax deductions will not be available; and

• the amount and timing of our income—the Tax Receivable Agreement generally will require us to pay 85% of the tax benefits as and when those benefits are treated as realized under the terms of the Tax Receivable Agreement. If we do not have taxable income, we generally will not be required (absent a change of control or other circumstances requiring an early termination payment) to make payments under the Tax Receivable Agreement for that taxable year because no tax benefits will have been actually realized. However, any tax benefits that do not result in realized tax benefits in a given taxable year will likely generate tax attributes that may be utilized to generate tax benefits in future taxable years. The utilization of any such tax attributes will result in payments under the Tax Receivable Agreement.

For purposes of the Tax Receivable Agreement, cash savings in income and franchise tax are computed by comparing our actual income and franchise tax liability to the amount of such taxes that we would have been required to pay (with an assumed tax rate for state tax purposes) had there been no Basis Adjustments and had the Tax Receivable Agreement not been entered into. The Tax Receivable Agreement generally applies to each of our taxable years. There is no maximum term for the Tax Receivable Agreement; however, the Tax Receivable Agreement may be terminated by us pursuant to an early termination procedure that requires us to pay the members of EnVen Equity Holdings an agreed upon amount equal to the estimated present value of the remaining payments to be made under the agreement (calculated based on certain assumptions, including regarding tax rates and utilization of the Basis Adjustments).

The payment obligations under the Tax Receivable Agreement are our obligations and not of EnVen GoM. Although the actual timing and amount of any payments that may be made under the Tax Receivable Agreement will vary, we may be required to make substantial payments to EnVen Equity Holdings or its members. For example, assuming (i) that EnVen Equity Holdings redeemed or exchanged all of its LLC Units immediately after the completion of this offering, (ii) no material changes in relevant tax law, and (iii) that we earn sufficient taxable income in each year to realize on a current basis all tax benefits that are subject to the Tax Receivable Agreement, based on the assumed initial public offering price of $         per share of our Class A common stock, which is the midpoint of the price range set forth on the cover page of this prospectus, we expect that the tax savings we would be deemed to realize would aggregate approximately $         million over the                  -year period from the assumed date of such redemption or exchange, and over such period we would be required to pay EnVen Equity Holdings or its members 85% of such amount, or approximately $         million, over such period. The actual amounts we may be required to pay under the Tax Receivable Agreement may materially differ from these hypothetical amounts, as potential future tax savings we will be deemed to realize, and Tax Receivable Agreement payments by us, will be calculated based in part on the market value of our Class A common stock at the time of redemption or exchange and the prevailing federal tax rates applicable to us over the life of the Tax Receivable Agreement (as well as the assumed combined state and local tax rate), and will generally be dependent on us generating sufficient future taxable income to realize all of these tax savings (subject to the exceptions described below). Any payments made by us to EnVen Equity Holdings or its members under the Tax Receivable Agreement will generally reduce the amount of overall cash flow that might have otherwise been available to us or to EnVen GoM and, to the extent that we are unable to make payments under the Tax Receivable Agreement for any reason, the unpaid amounts generally will be deferred and will accrue interest until paid by us.

Decisions made by us in the course of running our business, such as with respect to mergers, asset sales, other forms of business combinations or other changes in control, may influence the timing and amount of payments that are received by EnVen Equity Holdings or its members under the Tax Receivable Agreement. For example, the earlier disposition of assets following a transaction that results in a Basis Adjustment will generally accelerate payments under the Tax Receivable Agreement and increase the present value of such payments.

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The Tax Receivable Agreement provides that if (i) we materially breach any of our material obligations under the Tax Receivable Agreement, (ii) certain mergers, asset sales, other forms of business combinations, or other changes of control were to occur or (iii) we elect an early termination of the Tax Receivable Agreement, then our or our successor’s obligations under the Tax Receivable Agreement would accelerate and become due and payable, based on certain assumptions, including an assumption that we would have sufficient taxable income to fully utilize all potential future tax benefits that are subject to the Tax Receivable Agreement.

As a result, (i) we could be required to make payments under the Tax Receivable Agreement that are greater than the specified percentage of the actual benefits we ultimately realize in respect of the tax benefits that are subject to the Tax Receivable Agreement, and (ii) we could be required to make an immediate cash payment equal to the present value of the anticipated future tax benefits that are the subject of the Tax Receivable Agreement, which payment may be made significantly in advance of the actual realization, if any, of such future tax benefits. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or other changes of control. These provisions of the Tax Receivable Agreement may result in situations where the members of EnVen Equity Holdings have interests that differ from or are in addition to those of our other stockholders. There can be no assurance that we will be able to fund or finance our obligations under the Tax Receivable Agreement. If we were to exercise our right to terminate the Tax Receivable Agreement immediately after this offering, based on the initial public offering price of $         per share of our Class A common stock and a discount rate equal to the lesser of 6.5% and LIBOR plus 100 basis points, we estimate that we would be required to pay $         million in the aggregate under the Tax Receivable Agreement.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we determine. If any such position is subject to a challenge by a taxing authority, the outcome of which would reasonably be expected to materially affect a recipient’s payments under the Tax Receivable Agreement, then the recipient will have the right to participate in and to monitor at its own expense any such challenge. We will not be reimbursed for any cash payments previously made to EnVen Equity Holdings or, depending on the circumstances, any other recipient then a party to the Tax Receivable Agreement, if any tax benefits initially claimed by us are subsequently challenged by a taxing authority and ultimately disallowed. Instead, in such circumstances, any excess cash payments made by us to EnVen Equity Holdings or, depending on the circumstances, any other recipient then a party to the Tax Receivable Agreement, will be netted against any future cash payments that we might otherwise be required to make under the terms of the Tax Receivable Agreement. However, we might not determine that we have effectively made an excess cash payment pursuant to the Tax Receivable Agreement for a number of years following the initial time of such payment and, if our tax reporting positions are challenged by a taxing authority, we will not be permitted to reduce any future cash payments under the Tax Receivable Agreement until any such challenge is finally settled or determined. As a result, it is possible that we could make cash payments under the Tax Receivable Agreement that are substantially greater than our actual cash tax savings.

Payments are generally due under the Tax Receivable Agreement within a specified period of time following the filing of our tax return for the taxable year with respect to which the payment obligation arises, although interest on such payments will begin to accrue at a rate of LIBOR plus 100 basis points from the due date (without extensions) of such tax return. Any late payments that may be made under the Tax Receivable Agreement will continue to accrue interest at LIBOR plus 500 basis points until such payments are made, including any late payments that we may subsequently make because we did not have enough available cash to satisfy our payment obligations at the time at which they originally arose.

Because we are a holding company with no operations of our own, our ability to make payments under the Tax Receivable Agreement is dependent on the ability of EnVen GoM to make distributions to us. To the extent that we are unable to make payments under the Tax Receivable Agreement for any reason, the unpaid amounts generally will be deferred and will accrue interest until paid by us.

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As of June 30, 2018, there have been no exercises of Redemption Rights and there have been no payments made under with the Tax Receivable Agreement.

Shell Acquisition and the Series A Preferred Stock Offering

On December 30, 2016, we completed the Shell Acquisition and the Series A Preferred Stock Offering which resulted in the issuance of 3,708,334 shares of Series A preferred stock to Shell for $44.5 million of acquisition purchase price consideration. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Comparability—Series A Preferred Stock & Shell Acquisition.” As of December 31, 2017, we had issued 4,298,433 shares of Series A preferred stock to Shell, including 590,099 paid-in-kind dividends (“PIK shares”), which resulted in Shell owning more than 10% of our voting interests and qualified Shell as a principal owner of us, as defined in ASC Topic 850, Related Party Disclosures. In March 2018, we, along with certain of our equity investors, repurchased all of the shares of Series A preferred stock (including the PIK shares issued on March 31, 2018) owned by Shell. As a result of this repurchase, Shell no longer owns any of our Series A preferred stock or has any voting interest and no longer qualifies as one of our principal owners. See “Notes to Unaudited Consolidated Financial Statements—Note 14—Related Party Transactions” for a further discussion of this repurchase transaction.

Additionally, for the years ended December 31, 2017 and 2016, we received approximately $370 million and approximately $140 million, respectively, of revenue from Shell. See “Notes to Audited Consolidated Financial Statements—Note 15—Concentration Risk” for further discussion. Due to the fact that we have a related party relationship with Shell and Shell is also a major customer, we have identified and stated our transactions with Shell as related party transactions in the audited consolidated financial statements as of and for the years ended December 31, 2017 and 2016 and the unaudited consolidated financial statements as of and for the three and six months ended June 30, 2018 and 2017 included elsewhere in this prospectus.

Bain Capital Credit

Entities affiliated with Bain held 46.9% of our voting interest and three members of our board of directors are affiliated with Bain as of June 30, 2018. As of December 31, 2017, Bain was also a 30.5% lender participant, lending approximately $62 million out of $202.5 million outstanding as of December 31, 2017, in our Second Lien Term Loan that was terminated in connection with the 2018 Refinancing Transactions. See “Notes to Audited Consolidated Financial Statements—Note 8—Long-term Debt” for a discussion of the 2018 Refinancing Transactions. Immediately following the 2018 Refinancing Transactions, entities affiliated with Bain held 2023 Notes in the aggregate amount of approximately $36.8 million. See “Notes to Unaudited Consolidated Financial Statements—Note 14—Related Party Transactions”

EnVen GoM LLC Agreement

Pursuant to the EnVen GoM LLC Agreement, we serve as the manager of EnVen GoM, with full control over the business and affairs of EnVen GoM. Following this offering, the ownership interests in EnVen GoM will be comprised of a single class of common units and management incentive units provided to management, as the existing Series A preferred units will convert to common units in connection with this offering.

The EnVen GoM LLC Agreement requires that EnVen GoM at all times maintain a ratio of one LLC Unit owned by us for each share of Class A common stock issued by us to our common stockholders (subject to certain exceptions for treasury shares and shares underlying certain convertible or exchangeable securities). In addition, the EnVen GoM LLC Agreement provides the members of EnVen GoM, other than us, the Redemption Rights as discussed under “—Tax Receivable Agreement”; provided that at our election, we may effect a direct exchange of such Class A common stock or such cash payment for such LLC Units.

The holders of LLC Units will generally incur U.S. federal, state and local income taxes on their proportionate share of any net taxable income of EnVen GoM LLC. Net profits and net losses of EnVen GoM

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LLC will generally be allocated to its members pro rata in accordance with the percentages of their respective ownership of LLC Units, though certain non-pro rata adjustments will be made to reflect tax depreciation, amortization and other allocations. As a result of certain provisions of the EnVen GoM LLC Agreement, the allocations to us of tax depreciation and amortization and certain other items with respect to property previously contributed to EnVen GoM (including by EnVen Equity Holdings) may be significantly limited. The EnVen GoM LLC Agreement provides for pro rata cash distributions to the holders of LLC Units for purposes of funding their tax obligations in respect of the taxable income of EnVen GoM LLC that is allocated to them. Generally, these tax distributions are computed based on the estimated or actual taxable income of EnVen GoM LLC allocated to each holder of LLC Units multiplied by a tax rate determined in our sole discretion.

The EnVen GoM LLC Agreement provides that neither we, as manager of EnVen GoM, nor any of our affiliates will be liable for acts or omissions of us as manager, provided that such limitation on liability will not apply to any such act or omission that is attributable to gross negligence, willful misconduct or knowing violation of law or for any breaches of any representations, warranties or covenants in the EnVen GoM LLC Agreement or in other agreements with EnVen GoM. The EnVen GoM LLC Agreement also provides for indemnification against all expenses, liabilities and losses to the fullest extent permitted by Delaware law by virtue of a person being a member, the manager, or an officer, employee or other agent of EnVen GoM or serving at its request as a manager, officer, director, principal, member, employee or agent of another corporation, partnership, joint venture, limited liability company, trust or other enterprise, provided that such expenses, liabilities or losses were not the result of gross negligence, willful misconduct or knowing violation of law or for any breaches of any representations, warranties or covenants in the EnVen GoM LLC Agreement or in other agreements with EnVen GoM.

The EnVen GoM LLC Agreement also includes provisions with respect to restrictions on the transfer of the EnVen GoM’s units as well as the redemption rights detailed above under “—Tax Receivable Agreement.”

Registration Rights Agreements

On November 6, 2015, we entered into a registration rights agreement with certain investors (the “2015 Registration Rights Agreement”) under which we agreed, at our expense, to file with (or confidentially submit to) the SEC a shelf registration statement registering for the resale of the shares of Class A common stock held by such investors. Our obligation to file the shelf registration statement and to use our commercially reasonable efforts to cause such shelf registration statement to become and remain effective is not affected by the filing or effectiveness of a registration statement relating to the initial public offering of our Class A common stock, including this registration statement (an “IPO registration statement”).

The 2015 Registration Rights Agreement provides that in the event the managing underwriter or underwriters in any underwritten registered offering determine that, in its or their judgment, marketing factors require a limitation on the number of shares of Class A common stock to be registered, the shares of Class A common stock held by the holders party to the 2015 Registration Rights Agreement will be allocated first and not be reduced until all shares of Class A common stock held by certain other investors (or their transferees) have been excluded from such offering.

On November 6, 2015, we entered into another registration rights agreement (the “EEH Registration Rights Agreement”) with EnVen Equity Holdings providing EnVen Equity Holdings the right to cause us to include all or any number of our Class A common stock held by EnVen Equity Holdings (including shares of Class A common stock issuable to such holder upon exchange of its shares of Class B common stock and LLC Units) in any underwritten registered offering of our Class A common stock and to be included in any registration statement filed with the SEC for the offer and resale of Class A common stock by any other holder of Class A common stock; provided that EnVen Equity Holdings does not have such a right to have its Class A common stock included in an IPO registration statement. The EEH Registration Rights Agreement provides that in the event the managing underwriter or underwriters in any underwritten registered offering determine that, in its or

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their judgment, marketing factors require a limitation on the number of shares of Class A common stock to be registered, the number of shares of Class A common stock of EnVen Equity Holdings will be reduced first, and the shares of Class A common stock purchased and held by the parties to the 2015 Registration Rights Agreement (or their transferees) will not be reduced until all shares of Class A common stock held by EnVen Equity Holdings have been excluded from such offering.

The EEH Registration Rights Agreement also provides EnVen Equity Holdings and its members certain rights to have us file and cause to make effective a registration statement for the resale of all or any number of its Class A common stock held by EnVen Equity Holdings (including shares of Class A common stock issuable to such holder upon exchange of its shares of Class B common stock and LLC Units) following the expiration of any “lock-up” agreements entered into related to any initial public offering of shares of our Class A common stock.

On December 30, 2016, we entered into a registration rights agreement with the investors who purchased our Series A preferred stock on December 11, 2016 providing them the right to cause us to include all or any number of our Class A common stock converted from the shares of Series A preferred stock held by such investors in any underwritten registered offering of our Class A common stock, including this registration statement, and to be included in any registration statement filed with the SEC for the offer and resale of Class A common stock by any other holder of Class A common stock.

Effective upon consummation of this offering, we will enter into a Registration Rights Agreement (the “2018 Registration Rights Agreement”) with the Bain Investors. At any time beginning 180 days following the closing of this offering, subject to several exceptions, including underwriter cutbacks and our right to defer a demand registration under certain circumstances, the Bain Investors may require that we register for public resale under the Securities Act all ordinary shares constituting registrable securities that they request be registered so long as the securities requested to be registered in each registration statement have an aggregate estimated market value of at least $             million. If we become eligible to register the sale of our securities on Form S-3 under the Securities Act, which will not be until at least twelve months after the date of this prospectus, the Bain Investors have the right to require us to register the sale of the registrable securities held by them on Form S-3, subject to offering size and other restrictions.

If we propose to register any of our securities under the Securities Act for our own account or the account of any other holder (excluding any registration related to employee benefit plan, a corporate reorganization, other Rule 145 transactions, in connection with a dividend reinvestment plan or for the sole purpose of offering securities to another entity or its security holders in connection with the acquisition of assets or securities of such entity), the Bain Investors and certain other pre-IPO shareholders, including our executive officers, are entitled to notice of such registration and to request that we include registrable securities for resale on such registration statement, and we are required, subject to certain exceptions, to include such registrable securities in such registration statement.

In connection with the transfer of their registrable securities, the parties to the 2018 Registration Rights Agreement may assign certain of their respective rights under the 2018 Registration Rights Agreement under certain circumstances. In connection with the registrations described above, we will indemnify any selling stockholders and we will bear all fees, costs and expenses (except underwriting discounts and spreads).

Shareholders Agreement

In connection with this offering, we will enter into a shareholders agreement with the Bain Investors. Among other things, the shareholders agreement provides the Bain Investors with the right to nominate a certain number of directors to our board of directors, so long as the Bain Investors and their affiliates collectively beneficially own at least 10% of the outstanding shares of our Class A common stock.

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The shareholders agreement will provide that, subject to compliance with applicable law and NYSE rules, for so long as the Bain Investors and their affiliates beneficially own at least         % of our Class A common stock then outstanding, it shall be entitled to designate up to three nominees to our board of directors; for so long as the Bain Investors and their affiliates beneficially own at least 20% of our Class A common stock then outstanding, it shall be entitled to designate up to two nominees to our board of directors; and for so long as the Bain Investors and their affiliates beneficially own at least 10% of our Class A common stock then outstanding, it shall be entitled to designate up to one nominee to our board of directors.

In addition, the shareholders agreement will provide that for so long as the Bain Investors and their affiliates own at least         % of the outstanding shares of our Class A common stock, the Bain Investors will have the right to cause each of the nominating and corporate governance committee, the compensation committee and the audit committee of our board of directors to include in its membership at least one director designated by the Bain Investors, except to the extent that such membership would violate applicable securities laws or NYSE rules.

The shareholders agreement will also provide that for so long as the Bain Investors and their affiliates beneficially own at least 25% of our Class A common stock then outstanding, we agree not to take, or permit our subsidiaries to take, certain actions, such as incurring indebtedness or entering into a transaction that would result in a Change of Control (as defined therein), without the approval of the Bain Investors.

The rights granted to the Bain Investors to designate directors are additive to and not intended to limit in any way the rights that the Bain Investors or any of their affiliates may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the DGCL (as defined below).

Additionally, for as long as the Bain Investors and their affiliates hold at least         % of our outstanding Class A common stock, the Bain Investors, and their designated representatives will have certain information and access rights to our management.

Indemnification Agreements

Our bylaws provide that we will indemnify our directors and officers to the fullest extent permitted by the Delaware General Corporation Law (the “DGCL”), subject to certain exceptions contained in our bylaws. In addition, our certificate of incorporation provides that our directors will not be liable for monetary damages for breach of fiduciary duty.

The indemnification agreements will provide the executive officers and directors with contractual rights to indemnification, and expense advancement and reimbursement, to the fullest extent permitted under the DGCL, subject to certain exceptions contained in those agreements.

There is no pending litigation or proceeding naming any of our directors or officers to which indemnification is being sought, and we are not aware of any pending litigation that may result in claims for indemnification by any director or officer.

Policies and Procedures for Approval of Related Party Transactions

We have adopted a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

• any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

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• any person who is known by us to be the beneficial owner of more than 5% of our shares of Class A common stock or Class B common stock;

• any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our shares of Class A common stock or Class B common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our shares of Class A common stock and Class B common stock; and

• any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

Pursuant to this policy, our audit committee reviews all material facts of all Related Party Transactions.

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PRINCIPAL STOCKHOLDERS

The following table sets forth information as of                , 2018 (as adjusted to give effect to the Stock Split) regarding the beneficial ownership of shares of our Class A common stock, and as adjusted to reflect the completion of this offering, by:

• each person, or group of affiliated persons, known by us to beneficially own more than 5% of our shares of Class A common stock or Class B common stock;

• each of the directors and named executive officers individually; and

• all of our directors and executive officers as a group.

We have determined beneficial ownership in accordance with the rules of the SEC. These rules generally provide that a person is the beneficial owner of securities if such person has or shares the power to vote or direct the voting of securities, or to dispose or direct the disposition of securities, or has the right to acquire such powers within 60 days. For purposes of calculating each person’s percentage ownership, common stock issuable pursuant to options exercisable within 60 days are included as outstanding and beneficially owned for that person or group, but are not deemed outstanding for the purposes of computing the percentage ownership of any other person. Except as disclosed in the footnotes to this table and subject to applicable community property laws, we believe that each person identified in the table has sole voting and investment power over all of the shares shown opposite such person’s name.

The percentage of total shares of Class A common stock and Class B common stock to be beneficially owned is based on      shares of Class A common stock and Class B common stock as of         , including shares of our Class A common stock issuable upon the automatic conversion of our Series A preferred stock upon the closing of this offering. Unless otherwise noted, the address for each beneficial owner listed below is 333 Clay Street, Suite 4200, Houston, Texas 77002.

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As described in “Prospectus Summary—Our Organizational Structure” and “Certain Relationships and Related Party Transactions—EnVen GoM LLC Agreement,” each LLC Unit is redeemable for one share of Class A common stock, or, at our option, cash equal to the fair value of one of our Class A common stock. In addition, at our election, we may effect a direct exchange of such Class A common stock or such cash payment for such LLC Units.

	Shares Beneficially Owned Prior to this Offering			Shares Beneficially Owned After this Offering Assuming the Underwriters’ Option is Not Exercised			Shares Beneficially Owned After This Offering Assuming the Underwriters’ Option is Exercised in Full
Name of Beneficial Owner	Shares of Class A Common Stock	Shares of Class B Common Stock	% of Combined Voting Power	Shares of Class A Common Stock	Shares of Class B Common Stock	% of Combined Voting Power	Shares of Class A Common Stock	Shares of Class B Common Stock	% of Combined Voting Power
Principal Stockholders
Bain Capital Credit
Adage Capital Partners, L.P.
EIG Global Energy Partners
Directors and Named Executive Officers
Steven A. Weyel
David M. Dunwoody, Jr
John P. Wilkirson
Jon A. Jeppesen
Kenneth R. Olive, Jr.
Richard Sherrill
Andrew Hailey
John Ezekowitz
Christopher Linneman
Directors and executive officers as a group (                     persons)

* Represent beneficial ownership of less than 1%.

(1) Assumes no exercise of the underwriters’ option to purchase additional shares. See “Underwriting.”

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DESCRIPTION OF CAPITAL STOCK

The following description summarizes some of the terms of our Class A common stock, warrants, amended and restated certificate of incorporation and amended and restated bylaws that will become effective upon the closing of this offering and of the DGCL. Because it is only a summary, it does not contain all the information that may be important to you. For a complete description, you should refer to our amended and restated certificate of incorporation, and amended and restated bylaws, copies of which have been or will be filed as exhibits to the registration statement of which this prospectus forms a part, as well as the relevant provisions of the DGCL. The description of our Class A common stock and preferred stock reflects changes to our capital structure that will occur upon the closing of this offering.

Following this offering, our authorized capital stock will consist of                shares of Class A common stock, par value $0.01 per share,                  shares of Class B common stock, par value $0.01 per share, and                shares of preferred stock, par value $0.01 per share.

As of                  , 2018, there were                  shares of Class A common stock outstanding which were held of record by approximately                  holders and                  shares of our Series A preferred stock convertible into                  shares of our Class A common stock as of such date. There will be                shares of Class A common stock outstanding, assuming no exercise of the underwriters’ option to purchase additional shares and no exercise of outstanding options, after giving effect to the sale of the shares of Class A common stock offered hereby.

This section reflects the Stock Split, which will occur immediately prior to the completion of this offering.

Common Stock

Upon consummation of this offering (after giving effect to the Stock Split), there will be                 shares of our Class A common stock issued and outstanding and                 shares of our Class B common stock issued and outstanding.

Class A Common Stock

Voting Rights

Holders of our Class A common stock will be entitled to cast one vote per share. Holders of our Class A common stock will not be entitled to cumulate their votes in the election of directors. Generally, all matters to be voted on by stockholders must be approved by a majority (or, in the case of election of directors, by a plurality) of the votes entitled to be cast by all stockholders present in person or represented by proxy, voting together as a single class. Except as otherwise provided by law, amendments to the certificate of incorporation must be approved by a majority or, in some cases, a super-majority of the combined voting power of all shares entitled to vote, voting together as a single class.

Dividend Rights

Holders of Class A common stock will share ratably (based on the number of shares of Class A common stock held) if and when any dividend is declared by the board of directors out of funds legally available therefor, subject to any statutory or contractual restrictions on the payment of dividends and to any restrictions on the payment of dividends imposed by the terms of any outstanding preferred stock.

Liquidation Rights

On our liquidation, dissolution or winding up, each holder of Class A common stock will be entitled to a pro rata distribution of any assets available for distribution to common stockholders.

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Other Matters

No shares of Class A common stock will be subject to redemption or have preemptive rights to purchase additional shares of Class A common stock. Holders of shares of our Class A common stock do not have subscription, redemption or conversion rights. There will be no redemption or sinking fund provisions applicable to the Class A common stock. Upon consummation of this offering, all the outstanding shares of Class A common stock will be validly issued, fully paid and non-assessable.

Class B Common Stock

Issuance of Class B common stock with LLC Units

Shares of Class B common stock will only be issued in the future to the extent necessary to maintain a one- to-one ratio between the number of LLC Units held by EnVen Equity Holdings or, depending on the circumstances, its members and the number of shares of Class B common stock presently issued to EnVen Equity Holdings. Shares of Class B common stock are transferable only together with an equal number of LLC Units. Shares of Class B common stock will be cancelled on a one-for-one basis if, upon the exercise of a redemption right, we elect to redeem or exchange LLC Units of EnVen GoM or such member pursuant to the terms of the EnVen GoM LLC Agreement.

Voting Rights

Holders of Class B common stock are entitled to cast one vote per share, with the number of shares of Class B common stock held by EnVen Equity Holdings and each member being equivalent to the number of LLC Units held by EnVen Equity Holdings and such member. Holders of our Class B common stock are not entitled to cumulate their votes in the election of directors. Generally, all matters to be voted on by stockholders must be approved by a majority (or, in the case of election of directors, by a plurality) of the votes entitled to be cast by all stockholders present in person or represented by proxy, voting together as a single class. Except as otherwise provided by law, amendments to the certificate of incorporation must be approved by a majority or, in some cases, a super-majority of the combined voting power of all shares entitled to vote, voting together as a single class.

Dividend Rights

Holders of our Class B common stock do not participate in any dividend declared by the board of directors.

Liquidation Rights

On our liquidation, dissolution or winding up, holders of Class B common stock will not be entitled to receive any distribution of our assets.

Transfers

Pursuant to our certificate of incorporation and the EnVen GoM LLC Agreement, each holder of Class B common stock agrees that:

• the holder will not transfer any shares of Class B common stock to any person unless the holder transfers an equal number of LLC Units to the same person; and

• in the event the holder transfers any LLC Units (other than any LLC Units received upon conversion of a management incentive unit) to any person, the holder will transfer an equal number of shares of Class B common stock to the same person.

Other Matters

No shares of Class B common stock are subject to redemption rights or have preemptive rights to purchase additional shares of Class B common stock. Holders of shares of our Class B common stock do not have

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subscription, redemption or conversion rights (except to the extent that shares of Class B common stock may together with a corresponding number of LLC Units be exchanged for shares of Class A common stock on a one-for-one basis. See “Description of Capital Stock—EnVen GoM LLC Agreement.”) There are no redemption or sinking fund provisions applicable to the Class B common stock.

Preferred Stock

Our board of directors has the authority to issue the preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions thereof, including dividend rights, dividend rates, conversion rights, voting rights, terms of redemption, redemption prices, liquidation preferences and the number of shares constituting any series or the designation of such series, without further vote or action by the stockholders.

The issuance of preferred stock may have the effect of delaying, deferring or preventing a change in control without further action by the stockholders and may adversely affect the voting and other rights of the holders of common stock. At present, we have no plans to issue any additional amounts of preferred stock.

Series A Preferred Stock

As of June 30, 2018, we had 9,998,711 shares of Series A preferred stock outstanding. As a result of this offering, all the outstanding shares of the Series A preferred stock will be automatically converted into              shares of Class A common stock. See “Notes to Unaudited Condensed Consolidated Financial Statements—Note 9—Stockholders’ Equity.”

Warrants

The following description of the warrants is a summary of material provisions of the warrants and warrant agreements and is subject to, and is qualified in its entirety by reference to, all of the provisions of the warrant agreement applicable to a particular series of warrants.

After giving effect to the Stock Split, each Series A Warrant is exercisable for a              share of Class A common stock at an exercise price equal to $         per one share of Class A common stock. The aggregate number of shares of Class A common stock issuable upon exercise of all Series A Warrants is limited to              shares.

After giving effect to the Stock Split, each Series B Warrant is exercisable for a              share of Class A common stock at an exercise price equal to $         per one share of Class A common stock. The aggregate number of shares of Class A common stock issuable upon exercise of all Series B Warrants will be limited to              shares.

The exercise price of the warrants and number of shares of Class A common stock issuable upon exercise is subject to adjustments upon certain events, including changes in capital stock and reorganization of the Company.

Holders of the warrants will, in their capacity as holders, have:

• no right to vote on matters submitted to the stockholders of the Company;

• no right to receive dividends paid on capital stock of the Company; and

• no right to share in the assets of the Company in the event of its liquidation, dissolution or the winding up; in the event a bankruptcy or reorganization is commenced by or against the Company, a bankruptcy court may hold that unexercised warrants are executory contracts which may be subject to rejection by the Company with approval of the bankruptcy court, and the holders of the warrants may, even if sufficient funds are available, receive nothing or a lesser amount as a result of any such bankruptcy case than they would be entitled to if they had exercised their warrants prior to the commencement of any such case.

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The warrants were initially issued in the form of global securities held in book-entry form. Upon issuance, each of the global warrants was deposited with American Stock Transfer & Trust Company, LLC, the warrant agent, as custodian for The Depository Trust Company (“DTC”) and registered in the name of Cede & Co., as nominee of DTC. Ownership of beneficial interests in a global warrant is limited to persons who have accounts with DTC (“DTC participants”) or persons who hold interests through DTC participants. Beneficial interests in global warrants may not be exchanged for warrants in physical, certificated form except in limited circumstances. Owners of beneficial interests in a global warrant will not receive or be entitled to receive physical, certificated warrants. The global warrants and beneficial interests in the global warrants are subject to the applicable procedures of DTC, including procedures for exercising a beneficial interest in a warrant and restrictions on transfer.

The warrants may be exercised from the date when they are issued until the earlier of (i) December 8, 2020 or (ii) the third anniversary of the closing of this offering by delivering a duly executed exercise notice, together with payment of the exercise price. Under certain circumstances, the warrants may be exercised by means of a “cashless exercise” in which a warrant holder will be entitled to surrender a portion of the shares of Class A common stock subject to the warrant in lieu of cash for the exercise price.

Election and Removal of Directors

Our board of directors will consist of between      and     directors. The exact number of directors will be fixed from time to time by resolution of the board. No director may be removed except for cause; provided, however, that any director may be removed, with or without cause, from office by an affirmative vote of a majority of the total number of votes entitled to be cast by the holders of shares then outstanding at a meeting called for that purpose. Any vacancy occurring on the board of directors and any newly created directorship may be filled only by a majority of the remaining directors in office.

Our amended and restated certificate of incorporation provides that our board of directors will be divided into three classes of directors, with the classes to be as nearly equal in number as possible, and with the directors serving three-year terms. As a result, approximately one-third of our board of directors will be elected each year. The classification of directors will have the effect of making it more difficult for stockholders to change the composition of our board of directors.

Registration Rights

See “Certain Relationships and Related Party Transactions—Registration Rights Agreements” for more information about registration rights associated with Class A common stock.

Our Certificate of Incorporation and Bylaws

Provisions of our amended and restated certificate of incorporation and our amended and restated bylaws, which will become effective upon the closing of this offering, may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests. Therefore, these provisions could adversely affect the price of our Class A common stock.

Among other things, upon the completion of this offering, our certificate of incorporation and bylaws will:

• establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our bylaws specify the

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requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;

• provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

• provide that the authorized number of directors may be changed only by resolution of the board of directors;

• provide that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

• provide our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of the combined voting power of our then outstanding Class A common stock and Class B common stock;

• provide that our board of directors will be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms, other than directors that may be elected by holders of preferred stock, if any;

• provide that special meetings of our stockholders may only be called by the board of directors; and

• provide that our bylaws can be amended by the board of directors.

Anti-Takeover Effects of Some Provisions

Some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make the following more difficult:

• acquisition of control of us by means of a proxy contest or otherwise, or

• removal of our incumbent officers and directors.

These provisions, as well as our ability to issue preferred stock, are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection give us the potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us, and that the benefits of this increased protection outweigh the disadvantages of discouraging those proposals, because negotiation of those proposals could result in an improvement of their terms.

In addition, our amended and restated certificate of incorporation provides that we are not governed by Section 203 of the DGCL which, in the absence of such provisions, would have imposed additional requirements regarding mergers and other business combinations.

Exclusive Venue

Our amended and restated certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for:

• any derivative action or proceeding brought on our behalf;

• any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders;

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• any action asserting a claim against us arising pursuant to any provision of the DGCL, our certificate of incorporation or our bylaws; or

• any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.

Our certificate of incorporation will also provide that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and to have consented to, this forum selection provision. Although we believe these provisions will benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against our directors, officers, employees and agents. The enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could rule that this provision in our certificate of incorporation is inapplicable or unenforceable.

Limitation of Liability and Indemnification Matters

Our amended and restated certificate of incorporation will limit the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

• for any breach of their duty of loyalty to us or our stockholders;

• for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

• for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

• for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our bylaws will also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our bylaws also will permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision that will be in our certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Listing

We intend to apply to list our Class A common stock on the NYSE under the symbol “ENVN.”

Transfer Agent and Registrar

The transfer agent and registrar for our Class A common stock will be                .

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MATERIAL U.S. FEDERAL TAX CONSIDERATIONS FOR

NON-U.S. HOLDERS OF COMMON STOCK

The following is a general discussion of certain material U.S. federal income and estate tax consequences of the ownership and disposition of our Class A common stock by a “non-U.S. holder.” A “non-U.S. holder” is a beneficial owner of a share of our Class A common stock that is, for U.S. federal income tax purposes:

• a non-resident alien individual, other than a former citizen or resident of the United States subject to U.S. tax as an expatriate,

• a foreign corporation, or

• a foreign estate or trust.

If a partnership or other pass-through entity (including an entity or arrangement treated as a partnership or other type of pass-through entity for U.S. federal income tax purposes) owns our Class A common stock, the tax treatment of a partner or beneficial owner of the entity may depend upon the status of the owner, the activities of the entity and certain determinations made at the partner or beneficial owner level. Partners and beneficial owners in partnerships or other pass-through entities that own our Class A common stock should consult their own tax advisors as to the particular U.S. federal income and estate tax consequences applicable to them.

This discussion is based on the Code, administrative pronouncements, judicial decisions and final, temporary and proposed Treasury Regulations, changes to any of which subsequent to the date of this prospectus may affect the tax consequences described herein (possibly with retroactive effect). This discussion does not address all aspects of U.S. federal income and estate taxation that may be relevant to non-U.S. holders in light of their particular circumstances (including a foreign pension fund, “controlled foreign corporation” or “passive foreign investment company”) and does not address any tax consequences arising under the laws of any state, local or foreign jurisdiction. Prospective holders are urged to consult their tax advisors with respect to the particular tax consequences to them of owning and disposing of our Class A common stock, including the consequences under the laws of any state, local or foreign jurisdiction.

Dividends

To the extent that we pay dividends out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles), such dividends paid to a non-U.S. holder generally will be subject to U.S. federal withholding tax at a 30% rate, or a reduced rate specified by an applicable income tax treaty and may be subject to FATCA withholding taxes, as discussed below under “FATCA Withholding Taxes”. In order to obtain a reduced rate of withholding under an applicable income tax treaty, a non-U.S. holder generally will be required to provide a properly executed IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable form), as applicable, certifying its entitlement to benefits under the treaty.

Dividends paid to a non-U.S. holder that are effectively connected with the non-U.S. holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, are attributable to a permanent establishment or fixed base maintained by the non-U.S. holder in the United States) will not be subject to U.S. federal withholding tax if the non-U.S. holder provides a properly executed IRS Form W-8ECI. Instead, the effectively connected dividend income will generally be subject to regular U.S. income tax as if the non-U.S. holder were a United States person as defined under the Code. A non-U.S. holder that is treated as a corporation for U.S. federal income tax purposes receiving effectively connected dividend income may also be subject to an additional “branch profits tax” imposed at a rate of 30% (or a lower treaty rate) on its effectively connected earnings and profits (subject to certain adjustments).

Any portion of a distribution that exceeds our current and accumulated earnings and profits generally will be treated first as a tax-free return of capital, causing a reduction in a non-U.S. holder’s adjusted tax basis of our

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Class A common stock, and to the extent the amount of the distribution exceeds a non-U.S. holder’s adjusted tax basis in our Class A common stock, the excess will be treated as gain from the disposition of our Class A common stock (the tax treatment of which is discussed below under “—Gain on Disposition of Class A Common Stock”).

Gain on Disposition of Class A Common Stock

Subject to the discussions of backup withholding and FATCA withholding taxes below, a non-U.S. holder generally will not be subject to U.S. federal income tax on gain realized on a sale or other disposition of Class A common stock unless:

• the gain is effectively connected with a trade or business of the non-U.S. holder in the United States (and, if required by an applicable tax treaty, the gain is attributable to a permanent establishment or fixed base maintained by the non-U.S. holder in the United States), in which case the gain will be subject to U.S. federal income tax generally in the same manner as effectively connected dividend income as described above;

• the non-U.S. holder is an individual present in the United States for 183 days or more in the taxable year of disposition and certain other conditions are met, in which case the gain (net of certain US-source losses) generally will be subject to U.S. federal income tax at a rate of 30% (or a lower treaty rate); or

• we are or have been a “United States real property holding corporation” (as described below), at any time within the five-year period preceding the disposition or the non-U.S. holder’s holding period, whichever period is shorter, and either (i) our Class A common stock is not regularly traded on an established securities market prior to the beginning of the calendar year in which the sale or disposition occurs or (ii) the non-U.S. holder has owned or is deemed to have owned, at any time within the five-year period preceding the disposition or the non-U.S. holder’s holding period, whichever period is shorter, more than 5% of our Class A common stock.

We will be a United States real property holding corporation at any time that the fair market value of our “United States real property interests,” as defined in the Code and applicable Treasury Regulations, equals or exceeds 50% of the aggregate fair market value of our worldwide real property interests and our other assets used or held for use in a trade or business. We believe we are, and will be in the foreseeable future, a United States real property holding corporation. Accordingly, if either (i) our Class A common stock is not regularly traded on an established securities market during the calendar year in which the sale or other disposition occurs or (ii) the non-U.S. holder has owned or is deemed to have owned during the relevant period more than 5% of our Class A common stock, a non-U.S. holder may be subject to tax on the net gain from the sale or other disposition under the regular graduated U.S. federal income tax rates applicable to U.S. persons and could be subject to withholding at a 15% rate on the amount realized on such sale or other disposition. Non-U.S. holders, particularly those non-U.S. holders that could be treated as actually or constructively holding more than 5% of our Class A common stock, should consult their tax advisors regarding the particular U.S. federal income tax consequences of owning and disposing of our Class A common stock.

Information Reporting Requirements and Backup Withholding

Information returns are required to be filed with the IRS in connection with payments of dividends. A non-U.S. holder may have to comply with certification procedures to establish that it is not a U.S. person in order to avoid additional information reporting and backup withholding. The certification procedures required to claim a reduced rate of withholding under a treaty will generally satisfy the certification requirements necessary to avoid backup withholding as well. The amount of any backup withholding from a payment to a non-U.S. holder will be allowed as a credit against the non-U.S. holder’s U.S. federal income tax liability and may entitle the non-U.S. holder to a refund, provided that the required information is furnished to the IRS in a timely manner.

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FATCA Withholding Taxes

Payments to certain foreign entities of dividends on and (for dispositions after December 31, 2018) the gross proceeds of dispositions of Class A common stock of a U.S. issuer will be subject to a withholding tax (separate and apart from, but without duplication of, the withholding tax described above) at a rate of 30%, unless various U.S. information reporting and due diligence requirements (generally relating to ownership by U.S. persons of interests in or accounts with those entities) have been satisfied or an exemption from these rules applies. An intergovernmental agreement between the United States and an applicable foreign country may modify these requirements. Non-U.S. holders should consult their tax advisors regarding the possible implications of this withholding tax on their investment in our Class A common stock.

Federal Estate Tax

Individual non-U.S. holders (as specifically defined for U.S. federal estate tax purposes) and entities the property of which is potentially includible in such an individual’s gross estate for U.S. federal estate tax purposes (for example, a trust funded by such an individual and with respect to which the individual has retained certain interests or powers) should note that the Class A common stock will be treated as U.S. situs property subject to U.S. federal estate tax, unless an applicable estate tax treaty provides otherwise.

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no market for our Class A common stock. Future sales of substantial amounts of our Class A common stock in the public market could adversely affect market prices prevailing from time to time. Furthermore, because only a limited number of shares will be available for sale shortly after this offering due to existing contractual and legal restrictions on resale as described below, there may be sales of substantial amounts of our Class A common stock in the public market after the restrictions lapse. This may adversely affect the prevailing market price and our ability to raise equity capital in the future.

Upon completion of this offering and after giving effect to the Stock Split, we will have                shares of Class A common stock outstanding or                 shares if the underwriters exercise their option to purchase additional shares as well as                shares of Class B common stock that may be exchanged into                shares of Class A common stock in the future (as set forth below), assuming the conversion of all outstanding shares of preferred stock and no exercise of                options to purchase                shares outstanding as of                 , 2018. Of these shares, the                shares, or                shares if the underwriters exercise their option to purchase additional shares in full, sold in this offering will be freely transferable without restriction or registration under the Securities Act, except for any shares purchased by one of our existing “affiliates,” as that term is defined in Rule 144 under the Securities Act. The remaining                shares of Class A common stock existing are “restricted shares” as defined in Rule 144. Restricted shares may be sold in the public market only if registered or if they qualify for an exemption from registration under Rules 144 or 701 of the Securities Act.

We may issue shares of Class A common stock from time to time as consideration for future acquisitions, investments or other corporate purposes. In the event that any such acquisition, investment or other transaction is significant, the number of shares of Class A common stock that we may issue may in turn be significant. We may also grant registration rights covering those shares of Class A common stock issued in connection with any such acquisition and investment.

Each LLC Unit held by members of EnVen GoM, other than us, is redeemable, at the election of each member, for a cash payment equal to the fair value of one share of Class A common stock or, at our option, newly-issued shares of Class A common stock on a one-for-one basis (subject to customary adjustments, including for stock splits, stock dividends and reclassifications) in accordance with the terms of the EnVen GoM LLC Agreement; provided that, at our election, we may effect a direct exchange of such cash payment or such Class A common stock for such LLC Units. In addition, see “Prospectus Summary—Our Organizational Structure” for a discussion of our outstanding warrants. Upon consummation of this offering, the members of EnVen GoM, other than us, will hold      LLC units, all of which will be exchangeable for shares of our Class A common stock. The shares of Class A common stock we issue upon such exchanges would be “restricted securities” as defined in Rule 144 unless we register such issuances. However, we have entered into registration rights agreements with the members of GoM pursuant to which the shares of Class A common stock issued will be eligible for resale, subject to certain limitations set forth therein. See “Certain Relationships and Related Party Transactions—Registration Rights Agreements.”

Rule 144

In general, a person who has beneficially owned restricted shares of our Class A common stock for at least six months would be entitled to sell such securities, provided that (i) such person is not deemed to have been one of our affiliates at the time of, or at any time during the 90 days preceding, a sale and (ii) we are subject to the Exchange Act periodic reporting requirements for at least 90 days before the sale. Persons who have beneficially owned restricted shares of our Class A common stock for at least six months but who are our affiliates at the time of, or any time during the 90 days preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three month period only a number of securities that does not exceed the greater of either of the following:

• 1% of the number of shares of our Class A common stock then outstanding, which will equal approximately          shares immediately after this offering, assuming no exercise of the underwriters’ option to purchase additional shares; or

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• the average weekly trading volume of our Class A common stock on the NYSE during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale;

provided, in each case, that we are subject to the Exchange Act periodic reporting requirements for at least 90 days before the sale. Such sales both by affiliates and by non-affiliates must also comply with the manner of sale, current public information and notice provisions of Rule 144 to the extent applicable.

Rule 701

In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering is entitled to resell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirements or other restrictions contained in Rule 701.

The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus. Securities issued in reliance on Rule 701 are restricted securities and, subject to the contractual restrictions described above, beginning 90 days after the date of this prospectus, may be sold by persons other than “affiliates,” as defined in Rule 144, subject only to the manner of sale provisions of Rule 144 and by “affiliates” under Rule 144 without compliance with its one-year minimum holding period requirement.

Registration Rights

Upon completion of this offering, the holders of                shares of common stock and                shares of common stock issuable upon the exercise of outstanding options and warrants or their transferees, will be entitled to various rights with respect to the registration of these shares under the Securities Act. Registration of these shares under the Securities Act would result in these shares becoming freely tradable without restriction under the Securities Act immediately upon the effectiveness of the registration, except for shares purchased by affiliates.

For a description of rights some holders of our Class A common stock, our Class B common stock and our Series A preferred stock have to require us to register the shares of the stock they own, see “Certain Relationships and Related Party Transactions—Registration Rights Agreements.”

Stock Options

Upon completion of this offering, we intend to file a registration statement under the Securities Act covering all shares of Class A common stock subject to outstanding options or issuable pursuant to our 2015 Plan. Subject to Rule 144 volume limitations applicable to affiliates, shares registered under any registration statements will be available for sale in the open market, beginning 90 days after the date of the prospectus, except to the extent that the shares are subject to vesting restrictions with us or the contractual restrictions described below.

Lock-up Agreements

In connection with this offering, our directors, executive officers and certain holders of our capital stock, have agreed subject to certain exceptions, not to offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of, directly or indirectly, or enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of any shares of Class A common stock or any securities convertible into or exercisable or exchangeable for shares of Class A common stock for a period of

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180 days after the date of this prospectus, without the prior written consent of the representatives of the underwriters. See “Underwriting.”

Upon the expiration of the lock-up agreements in connection with this offering, up to an additional             shares of Class A common stock (or securities convertible into or exercisable or exchangeable for Class A common stock) will be eligible for sale in the public market, of which shares are held by directors, executive officers and other affiliates and will be subject to volume, manner of sale and other limitations under Rule 144.

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UNDERWRITING

We are offering the shares of Class A common stock described in this prospectus through a number of underwriters.                                                                                                                                                     are acting as book-running managers of the offering and as representatives of the underwriters. We have entered into an underwriting agreement with the underwriters. Subject to the terms and conditions of the underwriting agreement, we have agreed to sell to the underwriters, and each underwriter has severally agreed to purchase, at the public offering price less the underwriting discounts and commissions set forth on the cover page of this prospectus, the number of shares of Class A common stock listed next to its name in the following table:

Name	Number of Shares
Citigroup Global Markets Inc.
J.P. Morgan Securities LLC
Stifel, Nicolaus and Company, Incorporated
BMO Capital Markets Corp.
Total

The underwriters are committed to purchase all the common shares offered by us if they purchase any shares. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may also be increased or this offering may be terminated.

The underwriters propose to offer the common shares directly to the public at the initial public offering price set forth on the cover page of this prospectus and to certain dealers at that price less a concession not in excess of $                 per share. Any such dealers may resell shares to certain other brokers or dealers at a discount of up to $                 per share from the initial public offering price. After the initial public offering of the shares, the offering price and other selling terms may be changed by the underwriters.

The underwriters have an option to buy up to                  additional shares of Class A common stock from us to cover sales of shares by the underwriters which exceed the number of shares specified in the table above. The underwriters have 30 days from the date of this prospectus to exercise this option to purchase additional shares. If any shares are purchased with this option to purchase additional shares, the underwriters will purchase shares in approximately the same proportion as shown in the table above. If any additional shares of Class A common stock are purchased, the underwriters will offer the additional shares on the same terms as those on which the shares are being offered.

The underwriting fee is equal to the public offering price per share of Class A common stock less the amount paid by the underwriters to us per share of common stock. The underwriting fee is $                 per share. The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares.

	Without exercise of option to purchase additional shares	With exercise of option to purchase additional shares
Per share	$	$
Total	$	$

We estimate that the total expenses of this offering, including registration, filing and listing fees, printing fees and legal and accounting expenses, but excluding the underwriting discounts and commissions, will be approximately $                .

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A prospectus in electronic format may be made available on the web sites maintained by one or more underwriters, or selling group members, if any, participating in this offering. The underwriters may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the representative to underwriters and selling group members that may make Internet distributions on the same basis as other allocations.

We have agreed that we will not (i) offer, pledge, announce the intention to sell, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement under the Securities Act relating to, any shares of our Class A common stock or securities convertible into or exchangeable or exercisable for any shares of our Class A common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, or (ii) enter into any swap or other arrangement that transfers all or a portion of the economic consequences associated with the ownership of any shares of Class A common stock or any such other securities (regardless of whether any of these transactions are to be settled by the delivery of shares of Class A common stock or such other securities, in cash or otherwise), in each case without the prior written consent of the representatives for a period of 180 days after the date of this prospectus, other than the shares of our Class A common stock to be sold hereunder and any shares of our Class A common stock issued upon the exercise of options granted under our existing incentive and retention program.

Our directors, executive officers and certain shareholders have entered into lock-up agreements with the underwriters prior to the commencement of this offering pursuant to which each of these persons or entities, other than the shares to be sold hereunder and with limited exceptions, for a period of 180 days after the date of this prospectus, may not, without the prior written consent of the representatives, (1) offer, pledge, announce the intention to sell, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of, directly or indirectly, any shares of our Class A common stock or any securities convertible into or exercisable or exchangeable for our Class A common stock (including, without limitation, Class B common stock or such other securities which may be deemed to be beneficially owned by such directors, executive officers, managers and members in accordance with the rules and regulations of the SEC and securities which may be issued upon exercise of a stock option or warrant) or (2) enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the Class A common stock or such other securities, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of Class A common stock or such other securities, in cash or otherwise, or (3) make any demand for or exercise any right with respect to the registration of any shares of our Class A common stock or any security convertible into or exercisable or exchangeable for our Class A common stock.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act. We also agreed to reimburse the underwriters for certain expenses in connection with this offering in the amount not exceeding $        .

We intend to apply to list our Class A common stock on the NYSE under the symbol “ENVN”.

In connection with this offering, the underwriters may engage in stabilizing transactions, which involves making bids for, purchasing and selling shares of Class A common stock in the open market for the purpose of preventing or retarding a decline in the market price of the Class A common stock while this offering is in progress. These stabilizing transactions may include making short sales of the common stock, which involves the sale by the underwriters of a greater number of shares of Class A common stock than they are required to purchase in this offering, and purchasing shares of Class A common stock on the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional shares referred to above, or may be “naked” shorts, which are short positions in excess of that amount. The underwriters may close out any covered short position either by exercising their option to purchase additional shares, in whole or in part, or by purchasing shares in the open market. In making this determination, the underwriters will consider, among other things, the price of shares

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available for purchase in the open market compared to the price at which the underwriters may purchase shares through their option to purchase additional shares. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the Class A common stock in the open market that could adversely affect investors who purchase in this offering. To the extent that the underwriters create a naked short position, they will purchase shares in the open market to cover the position.

The underwriters have advised us that, pursuant to Regulation M of the Securities Act, they may also engage in other activities that stabilize, maintain or otherwise affect the price of the common stock, including the imposition of penalty bids. This means that if the representative of the underwriters purchases Class A common stock in the open market in stabilizing transactions or to cover short sales, the representative can require the underwriters that sold those shares as part of this offering to repay the underwriting discount received by them.

These activities may have the effect of raising or maintaining the market price of the Class A common stock or preventing or retarding a decline in the market price of the common stock, and, as a result, the price of the Class A common stock may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them at any time. The underwriters may carry out these transactions on the NYSE, in the over-the-counter market or otherwise.

Prior to this offering, there has been no public market for our Class A common stock. The initial public offering price will be determined by negotiations between us and the representative of the underwriters. In determining the initial public offering price, we and the representative of the underwriters expect to consider a number of factors including:

• the information set forth in this prospectus and otherwise available to the representative;

• our prospects and the history and prospects for the industry in which we compete;

• an assessment of our management;

• our prospects for future earnings;

• the general condition of the securities markets at the time of this offering;

• the recent market prices of, and demand for, publicly traded Class A common stock of generally comparable companies; and

• other factors deemed relevant by the underwriters and us.

Neither we nor the underwriters can assure investors that an active trading market will develop for our common shares, or that the shares will trade in the public market at or above the initial public offering price.

Other than in the United States, no action has been taken by us or the underwriters that would permit a public offering of the securities offered by this prospectus in any jurisdiction where action for that purpose is required. The securities offered by this prospectus may not be offered or sold, directly or indirectly, nor may this prospectus or any other offering material or advertisements in connection with the offer and sale of any such securities be distributed or published in any jurisdiction, except under circumstances that will result in compliance with the applicable rules and regulations of that jurisdiction. Persons into whose possession this prospectus comes are advised to inform themselves about and to observe any restrictions relating to the offering and the distribution of this prospectus. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any securities offered by this prospectus in any jurisdiction in which such an offer or a solicitation is unlawful.

Notice to Prospective Investors in Canada

The shares may be sold only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus Exemptions or subsection 73.3(1) of

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the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations. Any resale of the shares must be made in accordance with an exemption from, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory for particulars of these rights or consult with a legal advisor.

Pursuant to section 3A.3 of National Instrument 33-105 Underwriting Conflicts (NI 33-105), the underwriters are not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

Notice to Prospective Investors in the United Kingdom

This document is only being distributed to and is only directed at (i) persons who are outside the United Kingdom, (ii) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) and (iii) high net worth entities, and other persons to whom it may lawfully be communicated, falling with Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). The securities are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such securities will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

Notice to Prospective Investors in the European Economic Area

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), from and including the date on which the European Union Prospectus Directive (the “EU Prospectus Directive”) was implemented in that Relevant Member State (the “Relevant Implementation Date”) an offer of securities described in this prospectus may not be made to the public in that Relevant Member State prior to the publication of a prospectus in relation to the shares which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the EU Prospectus Directive, except that, with effect from and including the Relevant Implementation Date, an offer of securities described in this prospectus may be made to the public in that Relevant Member State at any time:

• to any legal entity which is a qualified investor as defined under the EU Prospectus Directive;

• to fewer than 150 natural or legal persons (other than qualified investors as defined in the EU Prospectus Directive); or

• in any other circumstances falling within Article 3(2) of the EU Prospectus Directive

provided that no such offer of securities described in this prospectus shall result in a requirement for the publication by us of a prospectus pursuant to Article 3 of the EU Prospectus Directive.

For the purposes of this provision, the expression an “offer of securities to the public” in relation to any securities in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the same may be varied in that Member State by any measure

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implementing the EU Prospectus Directive in that Member State. The expression “EU Prospectus Directive” means Directive 2003/71/EC (as amended by Directive 2010/73/EU) and includes any relevant implementing measure in each Relevant Member State.

Certain of the underwriters and their affiliates have provided in the past to us and our affiliates and may provide from time to time in the future certain commercial banking, financial advisory, investment banking and other services for us and such affiliates in the ordinary course of their business, for which they have received and may continue to receive customary fees and commissions. In addition, from time to time, certain of the underwriters and their affiliates may effect transactions for their own account or the account of customers, and hold on behalf of themselves or their customers, long or short positions in our debt or equity securities or loans, and may do so in the future.

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LEGAL MATTERS

The validity of the issuance of the shares of Class A common stock offered hereby will be passed upon for EnVen Energy Corporation by Davis Polk & Wardwell LLP. The validity of the shares of Class A common stock offered hereby will be passed upon for the underwriters by Simpson Thacher & Bartlett LLP.

EXPERTS

The consolidated financial statements of EnVen Energy Corporation and subsidiaries at December 31, 2017 and 2016, and for the years then ended, appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses of the Brutus Glider Properties for the years ended December 31, 2015 and 2014, included in this prospectus, have been so included in reliance on the report of Hein & Associates LLP, independent auditors, given on the authority of that firm as experts in auditing and accounting.

With respect to the unaudited interim financial information of the Brutus Glider Properties for the nine-month periods ended September 30, 2016 and 2015, included in this prospectus, Hein & Associates LLP has reported that they have applied limited procedures in accordance with professional standards for a review of such information. However, their separate report dated April 27, 2017, included herein, states that they did not audit and they do not express an opinion on that interim financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. Hein & Associates LLP is not subject to the liability provisions of section 11 of the Securities Act of 1933 for their report on the unaudited interim financial information because that report is not a “report” or a “part” of the registration statement prepared or certified by the accountants within the meaning of Sections 7 and 11 of the Act.

Estimates of our oil and natural gas reserves and related future net cash flows relating to all of our fields as of July 31, 2018 and December 31, 2017 and a portion of our fields as of December 31, 2016 are based upon the reserve reports prepared by Netherland, Sewell & Associates, Inc. We have included these estimates in reliance on the authority of such firm as experts in such matters.

Estimates of our oil and natural gas reserves and related future net cash flows relating to a portion of our fields as of December 31, 2016 are based upon the reserve report prepared by Ryder Scott Company, L.P. We have included these estimates in reliance on the authority of such firm as experts in such matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the Class A common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the company and our Class A common stock, reference is made to the registration statement and the exhibits and any schedules filed therewith. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance, if such contract or document is filed as an exhibit, reference is made to the copy of such contract or other document filed as an exhibit to the registration statement, each statement being qualified in all respects by such reference. A copy of the registration statement, including the exhibits and schedules thereto, may be read and copied at the SEC’s Public Reference Room at

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100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site at www.sec.gov, from which interested persons can electronically access the registration statement, including the exhibits and any schedules thereto.

As a result of the offering, we will become subject to the informational requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm. We also maintain an Internet site at www.enven.com. Our website and the information contained therein or connected thereto shall not be deemed to be incorporated into this prospectus or the registration statement of which it forms a part.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

EnVen Energy Corporation and Subsidiaries

	Page
Unaudited Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets as of June  30, 2018 and December 31, 2017		F-2
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2018 and 2017		F-3
Condensed Consolidated Statement of Changes in Equity for the Six Months Ended June 30, 2018		F-4
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017		F-5
Notes to Unaudited Condensed Consolidated Financial Statements		F-6
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm		F-30
Consolidated Balance Sheets as of December 31, 2017 and 2016		F-31
Consolidated Statements of Operations for Years Ended December  31, 2017 and 2016		F-32
Consolidated Statements of Changes in Equity for Years Ended December  31, 2017 and 2016		F-33
Consolidated Statements of Cash Flows for Years Ended December  31, 2017 and 2016		F-34
Notes to Consolidated Financial Statements		F-35
Brutus Glider Properties
Independent Auditor’s Report		F-72
Independent Auditor’s Review Report		F-73
Statements of Revenues and Direct Operating Expenses		F-74
Notes to Statements of Revenues and Direct Operating Expenses		F-75

F-1

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(In thousands, except share amounts)

(Unaudited)

	June 30, 2018			December 31, 2017
Assets:
Current assets:
Cash and cash equivalents	$	91,515		$	28,848
Current portion of restricted cash		9,398			6,789
Accounts receivable:
Oil, natural gas, and NGL revenue		62,898			9,483
Oil, natural gas, and NGL revenue - Related party		—			44,774
Joint interest and other		13,285			14,048
Income tax receivable		8,667			—
Prepaid expenses		22,356			21,584
Total current assets		208,119			125,526
Property and equipment:
Oil and natural gas properties, full cost method, including $23,353 and $12,648 of unevaluated properties not being amortized as of June 30, 2018 and December 31, 2017, respectively		1,143,597			1,058,539
Other property and equipment		6,623			4,212
Less: accumulated depreciation, depletion, and amortization		(467,734	)		(371,261	)
Property and equipment, net		682,486			691,490
Restricted cash		74,088			69,783
Notes receivable		50,315			13,982
Notes receivable - Related party		—			34,095
Other non-current assets		8,746			6,357
Other non-current assets - Related party		—			1,808
Total assets	$	1,023,754		$	943,041
Liabilities and Stockholders’ Equity:
Current liabilities:
Accounts payable	$	23,789		$	26,471
Accounts payable - Related party		—			621
Revenue and royalties payable		19,658			9,839
Revenue and royalties payable - Related party		—			7,226
Joint owner advances payable		530			578
Notes payable		3,345			8,308
Income tax payable		—			14,095
Accrued liabilities		54,543			38,610
Asset retirement obligations		26,751			21,828
Derivative liabilities		37,732			12,799
Total current liabilities		166,348			140,375
11.00% Senior notes due 2023, at fair value		352,830			—
Other long-term debt, net		—			292,195
Asset retirement obligations, less current portion		269,975			254,256
Derivative liabilities		4,039			5,094
Other non-current liabilities		1,139			736
Total liabilities		794,331			692,656
Commitments and contingencies (Note 11)
Stockholders’ equity:
Series A convertible perpetual preferred stock, $0.001 par value, 25,000,000 shares authorized
9,998,711 and 7,139,759 shares issued and outstanding as of June 30, 2018 and December 31, 2017, respectively		10			7
4,298,433 shares issued and outstanding as of December 31, 2017 - Related party		—			4
Class A common stock, $0.001 par value, 200,000,000 shares authorized and 16,134,918 and 16,075,244 shares issued and outstanding as of June 30, 2018 and December 31, 2017, respectively		16			16
Class B common stock, $0.001 par value, 50,000,000 shares authorized and 3,333,333 shares issued and outstanding as of June 30, 2018 and December 31, 2017		3			3
Additional paid-in capital		295,285			301,430
Accumulated deficit		(92,304	)		(78,874	)
Total stockholders’ equity		203,010			222,586
Non-controlling interest		26,413			27,799
Total equity		229,423			250,385
Total liabilities and equity	$	1,023,754		$	943,041

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-2

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(In thousands, except share and per share amounts)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Oil, natural gas, and NGL revenue	$	154,826		$	12,264		$	197,131		$	23,940
Oil, natural gas, and NGL revenue - Related party		—			83,767			101,147			183,744
Production handling and other income		3,921			5,278			7,662			8,092
Production handling and other income - Related party		—			185			154			597
Total revenues		158,747			101,494			306,094			216,373
Operating expenses:
Lease operating expenses		20,494			19,489			41,967			44,985
Lease operating expenses - Related party		—			2,303			—			9,525
Workover, repair, and maintenance expenses		8,314			4,342			11,985			7,634
Workover, repair, and maintenance expenses - Related party		—			391			—			1,195
Transportation, gathering, and processing costs		2,530			—			5,265			—
Depreciation, depletion, and amortization		49,064			40,947			96,473			88,911
General and administrative expenses		13,286			10,963			24,820			19,617
Accretion of asset retirement obligations		8,698			7,713			17,136			15,198
Total operating expenses		102,386			86,148			197,646			187,065
Operating income		56,361			15,346			108,448			29,308
Other (expense) income:
Interest expense		(13,435	)		(14,794	)		(37,551	)		(29,835	)
Loss on extinguishment of long-term debt		—			—			(4,012	)		—
Loss on fair value of 11.00% Senior notes due 2023		(24,580	)		—			(27,830	)		—
(Loss) gain on derivatives, net		(23,897	)		18,327			(37,649	)		41,141
Interest income		1,301			429			1,905			839
Interest income - Related party		—			642			568			1,272
Total other (expense) income		(60,611	)		4,604			(104,569	)		13,417
(Loss) income before income taxes		(4,250	)		19,950			3,879			42,725
Income tax expense		—			11,504			416			11,504
Net (loss) income		(4,250	)		8,446			3,463			31,221
Net (loss) income attributable to non-controlling interest		(445	)		1,051			338			4,767
Net (loss) income attributable to EnVen Energy Corporation		(3,805	)		7,395			3,125			26,454
Series A preferred stock dividends		(9,259	)		(2,774	)		(15,794	)		(5,497	)
Series A preferred stock dividends - Related party		—			(1,732	)		—			(3,401	)
Net (loss) income attributable to EnVen Energy Corporation common stockholders	$	(13,064	)	$	2,889		$	(12,669	)	$	17,556
Net (loss) income per common share - basic	$	(0.81	)	$	0.17		$	(0.79	)	$	1.06
Net (loss) income per common share - diluted	$	(0.81	)	$	0.17		$	(0.79	)	$	1.01
Weighted average common shares outstanding - basic		16,134,918			15,870,144			16,131,324			15,865,947
Weighted average common shares outstanding - diluted		16,134,918			15,870,144			16,131,324			25,924,066

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-3

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statement of Changes in Equity

(In thousands, except share amounts)

(Unaudited)

	Series A preferred stock						Class A common stock					Class B common stock
	Shares			Amount			Shares			Amount		Shares		Amount		Additional paid-in capital			Accumulated deficit			Total stockholders’ equity			Non-controlling interest			Total equity
Balance as of January 1, 2018		11,438,192		$	11			16,075,244		$	16		3,333,333	$	3	$	301,430		$	(78,874	)	$	222,586		$	27,799		$	250,385
Issuance of Class A common stock related to stock-based compensation		—			—			87,378			—		—		—		—			—			—			—			—
Tax payments related to stock-based compensation		—			—			(27,704	)		—		—		—		(435	)		—			(435	)		—			(435	)
Stock-based compensation		—			—			—			—		—		—		3,668			—			3,668			—			3,668
Repurchase of Series A preferred stock - Related party		(2,149,217	)		(2	)		—			—		—		—		(25,789	)		—			(25,791	)		—			(25,791	)
Series A preferred stock dividends		709,736			1			—			—		—		—		8,515			(8,516	)		—			—			—
Series A preferred stock dividends beneficial conversion feature		—			—			—			—		—		—		7,278			(7,278	)		—			—			—
Change in ownership due to Series A preferred stock repurchase and dividends		—			—			—			—		—		—		618			—			618			(618	)		—
Distributions to non-controlling interest owners		—			—			—			—		—		—		—			—			—			(1,012	)		(1,012	)
Cumulative effect of ASC 606 accounting change		—			—			—			—		—		—		—			(761	)		(761	)		(94	)		(855	)
Net (loss) income		—			—			—			—		—		—		—			3,125			3,125			338			3,463
Balance as of June 30, 2018		9,998,711		$	10			16,134,918		$	16		3,333,333	$	3	$	295,285		$	(92,304	)	$	203,010		$	26,413		$	229,423

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-4

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	Six Months Ended June 30,
	2018			2017
Cash flows from operating activities:
Net income	$	3,463		$	31,221
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		96,473			88,911
Accretion of asset retirement obligations		17,136			15,198
Loss on disposition of property and equipment		—			(19	)
Stock-based compensation		3,668			2,491
Excess tax benefit from stock-based compensation		90			—
Amortization and expensing of debt issuance costs		12,378			4,909
Loss on extinguishment of long-term debt		4,012			—
Loss on fair value of 11.00% Senior notes due 2023		27,830			—
Derivative instruments:
Loss (gain) on derivatives, net		37,649			(41,141	)
Cash (paid) received for derivative settlements, net		(13,771	)		16,010
Other non-cash items		(3,069	)		(1,749	)
Changes in operating assets and liabilities:
Accounts receivable		(52,652	)		(9,786	)
Accounts receivable - Related party		44,774			(11,906	)
Income tax receivable		(8,758	)		—
Prepaid expenses		(772	)		(11,739	)
Accounts payable		(2,682	)		6,573
Accounts payable - Related party		(621	)		348
Revenue and royalties payable		9,819			(5,129	)
Revenue and royalties payable - Related party		(7,226	)		5,139
Joint owner advances payable		(48	)		1,894
Income tax payable		(14,095	)		11,504
Accrued liabilities		17,925			(1,821	)
Settlement of asset retirement obligations		(3,149	)		(15,500	)
Other non-current liabilities		425			(37	)
Net cash provided by operating activities	$	168,799		$	85,371
Cash flows from investing activities:
Purchases of property and equipment	$	(75,395	)	$	(26,890	)
Purchases of oil and natural gas leases		(7,410	)		—
Change in other		—			(1,637	)
Net cash used in investing activities	$	(82,805	)	$	(28,527	)
Cash flows from financing activities:
Proceeds from issuance of long-term debt	$	325,000		$	—
Payments on long-term debt		(297,500	)		(80,625	)
Payment of debt issuance costs		(9,554	)		—
Premium paid for early termination of long-term debt		(2,025	)		—
Payment to repurchase Series A preferred stock - Related party		(25,791	)		—
Tax payments related to stock-based compensation		(435	)		—
Proceeds from issuance of notes payable		—			9,700
Payments on notes payable		(5,096	)		(4,155	)
Distributions to non-controlling interest owners		(1,012	)		—
Net cash used in financing activities	$	(16,413	)	$	(75,080	)
Net increase (decrease) in cash, cash equivalents, restricted cash, and restricted cash equivalents	$	69,581		$	(18,236	)
Cash, cash equivalents, restricted cash, and restricted cash equivalents - beginning of period	$	105,420		$	98,103
Cash, cash equivalents, restricted cash, and restricted cash equivalents - end of period	$	175,001		$	79,867

The accompanying notes are an integral part of these condensed consolidated financial statements.

Refer to Note 13 - Supplemental Cash Flow Information for supplemental cash flow disclosures.

F-5

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 - Organization

EnVen Energy Corporation (individually or together with its subsidiaries, the “Company”) is an independent oil and natural gas company engaged in the development, exploitation, exploration, and acquisition of primarily crude oil properties in the deepwater region of the United States (“U.S.”) Gulf of Mexico. The Company focuses on developing and acquiring producing deepwater assets that it believes have untapped development opportunities and will provide strong cash flow and lower-risk development with significant exploration potential. This strategy allows the Company to benefit from the favorable geologic and economic characteristics of the deepwater U.S. Gulf of Mexico.

Note 2 - Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation and Consolidation

The accompanying unaudited condensed consolidated financial statements as of June 30, 2018 and for the three and six months ended June 30, 2018 and 2017 are prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) and include the accounts for the Company and entities in which it has control. All significant intercompany balances and transactions have been eliminated. The Company owns the majority interest (approximately 88.7% and 89.2% as of June 30, 2018 and December 31, 2017, respectively) of and controls its subsidiary, Energy Ventures GoM LLC (“EnVen GoM”); therefore, the majority interest in EnVen GoM is reflected as a consolidated subsidiary in the accompanying unaudited condensed consolidated financial statements. The remaining ownership interest (approximately 11.3% and 10.8% as of June 30, 2018 and December 31, 2017, respectively) not held by the Company (the “Non-controlling Interest”) is included in the accompanying unaudited condensed consolidated financial statements as Non-controlling interest. EnVen GoM is considered a variable interest entity (“VIE”) for which the Company is the primary beneficiary, as the Company is the sole managing member of EnVen GoM and has the power to direct the activities most significant to EnVen GoM’s economic performance, as well as the obligation to absorb losses and receive benefits that are potentially significant. Refer to Note 9 - Stockholders’ Equity for further discussion of the Company’s ownership of EnVen GoM.

The condensed consolidated financial statements as of June 30, 2018 and for the three and six months ended June 30, 2018 and 2017 are unaudited. The condensed consolidated financial statements as of December 31, 2017 were derived from the audited consolidated financial statements included in the Company’s 2017 Annual Financial Report for the years ended December 31, 2017 and 2016 (the “2017 Annual Financial Report”). In preparing the accompanying unaudited condensed consolidated financial statements, the Company has evaluated events or transactions through the date these unaudited condensed consolidated financial statements are available to be issued. In management’s opinion, all normal recurring adjustments necessary for the fair presentation of the Company’s interim and prior period results have been made.

Certain disclosures have been condensed in or omitted from these condensed consolidated financial statements, however, management believes the disclosures are adequate to make the information not misleading. The accompanying unaudited condensed consolidated financial statements and related note disclosures should be read in conjunction with the consolidated financial statements and related notes thereto included in the Company’s 2017 Annual Financial Report.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of

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contingent assets and liabilities at the date of the financial statements. Management believes its estimates and assumptions to be reasonable under the circumstances. Certain estimates and assumptions are inherently unpredictable and actual results could differ from those estimates.

The Company has provided a discussion of significant accounting policies, estimates, and judgments in Note 1 - Organization and Summary of Significant Accounting Policies in its 2017 Annual Financial Report.

During the six months ended June 30, 2018, the Company changed certain of its significant accounting policies relating to the items discussed below:

Revenue - Adoption of ASC 606

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09 (“ASU 2014-09”) as a new Accounting Standards Codification (“ASC”) Topic 606, which supersedes revenue recognition requirements in ASC Topic 605, Revenue Recognition (“ASC 605”). This standard requires an entity to recognize the amount of revenue to which it expects to be entitled to for the transfer of goods or services promised to customers and requires entities to disclose the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance, including guidance pertaining to the presentation of revenues on a gross-versus-net basis and the use of the entitlements method to account for natural gas imbalances (collectively, “ASC 606”). The Company adopted ASC 606 effective January 1, 2018 using the modified retrospective approach, applied to contracts that were not completed as of January 1, 2018. The Company applied this change in accounting policy prospectively, therefore, revenues reported in periods prior to January 1, 2018 did not change.

As a result of the implementation, the Company no longer uses the entitlements method of accounting for its natural gas imbalances, as this standard has superseded previous revenue guidance, and has recognized an immaterial change to the transaction price allocated to the remaining performance obligations in certain production handling contracts. Due to these changes, the Company recognized a cumulative effect adjustment in the opening balance of accumulated deficit as of June 30, 2018 and an immaterial net impact to net loss for the three and six months ended June 30, 2018.

The adoption of the standard did not have a material impact on the timing of the Company’s revenue recognition, financial position, results of operations, net loss, or cash flows but did impact its revenue-related disclosures and future presentation of revenues and expenses. Prior to the adoption of the standard, the Company presented its oil, natural gas, and NGL revenues net of transportation, gathering, and processing costs. The new guidance specifies that, if the Company controls the product throughout processing before it is transferred to the customer, then the transportation, gathering, and processing costs associated with that product should be included as a component of operating expense and not as a reduction of revenue. Therefore, as of January 1, 2018, oil, natural gas, and NGL revenues for the Company’s operated properties are presented gross of certain transportation, gathering, and processing costs incurred prior to the transfer of control and the transportation, gathering, and processing costs are presented as a component of operating expense. The change from net to gross presentation resulted in an increase in the Company’s oil, natural gas, and NGL revenues and a corresponding increase in operating expenses.

F-7

The following tables present the effects of ASC 606 for the three and six months ended June 30, 2018:

	Three Months Ended June 30, 2018
	Under ASC 606			Under ASC 605			Change
	(In thousands)
Revenues:
Oil revenue	$	140,685		$	139,975		$	710
Natural gas revenue		12,837			11,322			1,515
NGL revenue		1,304			960			344
Production handling and other income		3,921			3,868			53
Total revenues	$	158,747		$	156,125		$	2,622
Operating expenses:
Transportation, gathering, and processing costs	$	2,530		$	—		$	2,530
Net loss	$	(4,250	)	$	(4,342	)	$	92

	Six Months Ended June 30, 2018
	Under ASC 606		Under ASC 605		Change
	(In thousands)
Revenues:
Oil revenue	$	272,056	$	270,526	$	1,530
Natural gas revenue		22,547		19,891		2,656
NGL revenue		3,675		2,796		879
Production handling and other income		7,816		7,581		235
Total revenues	$	306,094	$	300,794	$	5,300
Operating expenses:
Transportation, gathering, and processing costs	$	5,265	$	—	$	5,265
Net income	$	3,463	$	3,428	$	35

Revenue Recognition

As of January 1, 2018, the Company recognizes sales of oil, natural gas, and NGLs at the point that control of the product is transferred to the customer. Production handling revenue is recognized over time as the Company performs on the service contract.

Virtually all of the Company’s product contract pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGL supplies.

The Company’s contracts with its customers state the terms of the sale, including the description, quantity, and price of each product sold. According to the contracts, the Company invoices customers once its performance obligations have been satisfied, at which point the right to payment is unconditional. Accordingly, these contracts do not give rise to contract assets or liabilities under ASC 606. Depending on the product sold, payments from customers are generally due in full within 30 days of the product delivery or invoice date. The Company has determined that product returns or refunds are very rare and will account for them as they occur, and it generally provides no warranty other than the implicit promise that goods delivered are free of liens and encumbrances and meet the agreed upon specification.

The Company has elected to apply the sales tax practical expedient, whereby certain qualifying taxes collected from customers and remitted to governmental authorities are not included in reported revenues, but rather, are presented as component of operating expense in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2018.

F-8

The Company records revenue in the month production is delivered to the purchaser. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required 30 days after the end of the production month. As a result, at the end of each month when the performance obligation is satisfied, the Company is required to estimate the variable consideration using the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Amounts due from purchasers are accrued in oil, natural gas, and NGL revenue accounts receivable on the accompanying unaudited condensed consolidated balance sheets. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser.

Generally, all of the Company’s sales contracts, other than production handling service contracts discussed further below, are short-term in nature with a contract term of one year or less. As such, the Company has elected to utilize the practical expedient within ASC 606-10-50-14 exempting it from the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Additionally, under the Company’s contracts, each unit of product represents a separate wholly unsatisfied performance obligation for which the variable payment relates specifically to the efforts to satisfy that performance obligation and allocating the variable consideration is consistent with the allocation objective. Therefore, disclosure of the transaction price allocated to remaining performance obligations is not required under ASC 606-10-32-40.

Revenue Contracts

Oil. The Company’s oil revenue contracts are generally structured so that it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. In certain arrangements, the Company pays a third-party to transport the product and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as a component of operating expense in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2018.

Natural gas and NGLs. Under the Company’s natural gas processing contracts, the Company delivers natural gas to a processing entity at the wellhead or the inlet of the processing entity’s system. In these contracts, the Company may elect to take residue gas and/or NGLs in-kind at the tailgate of the processing plant and subsequently market the product. Through the marketing process, the Company delivers the product to the purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. This purchaser can be the natural gas processor or the processor can market the product on the Company’s behalf to a third-party purchaser. In both scenarios, the Company has concluded it is the principal in the transaction as control of the product remains with the Company throughout the process. The Company recognizes revenue when control transfers to the ultimate purchaser at the delivery point based on the index price received from the purchaser. Any fees paid to the processor are considered to be for a distinct service with an identifiable benefit that is sufficiently separable. The gathering, processing, and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as a component of operating expense in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2018.

Production handling services. The Company’s production handling services contracts are negotiated in situations where it has a significant working interest in a platform with excess capacity to process and handle produced oil and natural gas. The Company provides processing services to customers with nearby property interests who wish to utilize its excess processing capacity for their production. In certain situations, the Company will also provide services for the operation of the producer’s satellite subsea system. Under these contracts, the Company receives fees for volumes delivered by the customer and processed by the Company. The nature of production handling services is inherently output based on volumes processed and the Company recognizes revenue over time using the output method.

F-9

As of June 30, 2018, the Company had approximately $9.3 million of remaining performance obligations related to production handling service contracts with expected durations of five to thirteen years. The Company expects to recognize approximately $1.8 million of these performance obligations as revenue annually over the next five and a half years and the remaining amount allocated to these performance obligations ratably over the following seven and a half years. The transaction price for these contracts is comprised of both fixed and variable consideration which is resolved monthly as the distinct service is provided. The fixed consideration typically relates to monthly minimum fees or production system operation fees. Variable consideration may include operating, infrastructure access, and production handling fees which are based on either contractual rates for units of production serviced or a proportionate expense fee.

11.00% Senior notes due 2023

In February 2018, the Company completed a private offering of $325.0 million aggregate principal amount of 11.0% senior secured second lien notes due 2023 (the “2023 Notes”), resulting in net proceeds of $317.0 million, after deducting initial purchaser fees and offering expenses of $8.0 million (the “2023 Notes Offering”).

The 2023 Notes indenture contains certain put and call features that were analyzed for potential bifurcation as embedded derivatives in accordance with ASC Topic 815, Derivatives and Hedging (“ASC 815”). The Company determined that one of these options is not clearly and closely related to the risks and rewards of the 2023 Notes in which it is embedded and therefore requires bifurcation. Due to this embedded derivative feature, the Company has elected to account for the 2023 Notes and all of its features using the fair value option, in accordance with ASC 815. Therefore, the Company has recorded the 2023 Notes at their fair value on the accompanying unaudited condensed consolidated balance sheet as of June 30, 2018 and the change in fair value as Loss on fair value of 11.00% Senior notes due 2023 on the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2018. At the end of each reporting period, the Company will remeasure the fair value of the 2023 Notes and will recognize the changes in fair value as a gain or loss on fair value of 11.00% Senior notes due 2023. Additionally, due to the fair value option election in accordance with ASC 815, the Company expensed debt issuance costs of $8.0 million associated with the 2023 Notes to Interest expense on the accompanying unaudited condensed consolidated statement of operations for the six months ended June 30, 2018.

Refer to Note 8 - Long-term Debt for further discussion of the 2023 Notes and the related embedded features.

Debt Issuance Costs

At the time of the 2023 Notes Offering, the Company made certain amendments to its first lien senior secured revolving credit facility (the “Revolving Credit Facility”) and terminated its second lien term loan facility (the “Second Lien Term Loan” and together with the 2023 Notes Offering, the “2018 Refinancing Transactions”). Refer to Note 8 - Long-term Debt for further discussion of the 2018 Refinancing Transactions.

Prior to the 2018 Refinancing Transactions, the debt issuance costs related to the Company’s Second Lien Term Loan were capitalized as deferred financing costs and amortized over the term of the agreement. The unamortized portion of the deferred financing costs was included as a reduction to the outstanding balance of the Second Lien Term Loan, which was recorded as Other long-term debt, net on the accompanying unaudited condensed consolidated balance sheet as of December 31, 2017.

At the time of the 2018 Refinancing Transactions, the Company applied ASC Topic 470-50, Modifications and Extinguishment of Debt and determined that the terms of the 2023 Notes and the Second Lien Term Loan were not substantially different for certain of the lenders that participated in both of the debt instruments as the lender-specific present value of the cash flows under the terms of the 2023 Notes was not at least 10% different from the present value of the remaining cash flows under the terms of the Second Lien Term Loan. Therefore, a portion of the 2023 Notes are considered to be a modification of the Second Lien Term Loan. The portion of the Second Lien Term Loan associated with continuing lenders with substantially different cash flows between debt instruments and with lenders that did not choose to participate in the 2023 Notes was considered extinguished.

F-10

As a result, the Company allocated the unamortized portion of the deferred financing costs and original issue discount associated with the Second Lien Term Loan and a 1.0% premium paid to creditors for early termination of the Second Lien Term Loan between modification and extinguishment accounting, resulting in extinguishment related costs of $4.0 million recorded as Loss on extinguishment of long-term debt on the accompanying unaudited condensed consolidated statement of operations for the six months ended June 30, 2018 and modification related costs of $2.7 million recorded as Interest expense, due to the fair value option election discussed above, on the accompanying unaudited condensed consolidated statement of operations for the six months ended June 30, 2018. Additionally, the Company expensed $8.0 million of debt issuance costs associated with the 2023 Notes, including modification related costs attributable to the continuing lenders of $1.5 million, as Interest expense on the accompanying unaudited condensed consolidated statement of operations for the six months ended June 30, 2018.

As the Company’s borrowing capacity under its Revolving Credit Facility increased for each lender in connection with the amendment to the facility as part of the 2018 Refinancing Transactions, the initial debt issuance costs remain capitalized as deferred financing costs, along with $1.6 million of incremental costs incurred for the amendment. These costs are amortized over the term of the amended agreement. The unamortized portion of the deferred financing costs are included in Other non-current assets on the accompanying unaudited condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017.

Recently Issued Accounting Standards - Adopted

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which requires the amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning of the period and end of period totals in the statement of cash flows. The Company adopted this standard effective December 31, 2017 using the retrospective approach.

Refer to Note 13 - Supplemental Cash Flow Information for a reconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents reported on the accompanying unaudited condensed consolidated statements of cash flows.

Recently Issued Accounting Standards - Not Yet Adopted

In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”), which requires an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. In February 2018, the FASB issued ASU 2018-03, Technical Corrections and Improvements to Financial Instruments (Subtopic 825-10) - Recognition and Measurement of Financial Assets and Financial Liabilities. This update was issued to clarify certain narrow aspects of guidance concerning the recognition of financial assets and liabilities established in ASU 2016-01. For non-public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2019 and interim periods within fiscal years beginning after December 15, 2019. For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The Company continues to evaluate the impact the adoption of this ASU may have on its consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016–02, Leases (Topic 842) (“ASU 2016-02”), which will require lessees to recognize a right-of-use asset and a lease liability on their balance sheet for all leases, including operating leases, with a term of greater than 12 months. ASU 2016–02 will also require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. Subsequent to the issuance of ASU 2016-02, the FASB issued various clarifications and interpretive guidance. For non-public entities, ASU 2016-02 is

F-11

effective for fiscal years beginning after December 15, 2019 and interim periods within fiscal years beginning after December 15, 2020. For public entities, ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. The Company continues to evaluate the impact the adoption of this ASU may have on its consolidated financial statements and has engaged a third-party specialist to assist in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Standard setting guidance and interpretations continue to evolve and are being monitored for applicability and impact to the Company’s business and industry. Based on an initial review of the new ASU and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time.

Note 3 - (Loss) Earnings per Share

Basic net (loss) earnings per common share is calculated by dividing the Net (loss) income attributable to EnVen Energy Corporation common stockholders by the weighted average common shares outstanding for the period. The Company’s restricted stock awards and units (the “Restricted Stock”) is considered to be a participating security; therefore, in periods with net income, undistributed earnings are allocated among the Company’s common shares and issued non-vested Restricted Stock shares per the two-class method.

Diluted earnings per share is calculated by dividing Net income allocated to common shares by the weighted average common shares outstanding during the period, including potentially dilutive common shares outstanding during the period determined by the treasury stock method. Potentially dilutive common shares are determined by including the following, as applicable, in the periods presented: (i) the vesting of Restricted Stock, (ii) the exercise of stock options at an average price greater than their exercise price, (iii) the exercise of warrants at an average price greater than their exercise price, and (iv) the conversion of preferred shares.

The Company’s basic and diluted (loss) earnings per common share calculations are as follows for the periods indicated:

	Three Months Ended June 30, 2018
	Loss			Weighted Average Shares Outstanding		Loss per Share
	(In thousands, except share and per share amounts)
Basic and diluted:
Net loss attributable to EnVen Energy Corporation common stockholders	$	(13,064	)		16,134,918	$	(0.81	)
Potentially anti-dilutive shares excluded from weighted average shares outstanding					11,363,402

	Three Months Ended June 30, 2017
	Income			Weighted Average Shares Outstanding		Earnings per Share
	(In thousands, except share and per share amounts)
Basic and diluted:
Net income attributable to EnVen Energy Corporation common stockholders	$	2,889
Less: Undistributed earnings allocated to non-vested restricted stock		(149	)
Net income available to common stockholders	$	2,740			15,870,144	$	0.17
Potentially anti-dilutive shares excluded from weighted average shares outstanding					12,457,527

F-12

	Six Months Ended June 30, 2018
	Loss			Weighted Average Shares Outstanding		Loss per Share
	(In thousands, except share and per share amounts)
Basic and diluted:
Net loss attributable to EnVen Energy Corporation common stockholders	$	(12,669	)		16,131,324	$	(0.79	)
Potentially anti-dilutive shares excluded from weighted average shares outstanding					11,953,820

	Six Months Ended June 30, 2017
	Income			Weighted Average Shares Outstanding		Earnings per Share
	(In thousands, except share and per share amounts)
Basic:
Net income attributable to EnVen Energy Corporation common stockholders	$	17,556
Less: Undistributed earnings allocated to non-vested restricted stock		(804	)
Net income available to common stockholders	$	16,752			15,865,947	$	1.06
Diluted:
Effect of dilutive securities:
Add: Undistributed earnings allocated to restricted stock shares	$	804
Add: Increase in net income available to common stockholders if assumed preferred stock conversion		9,051
Less: Undistributed earnings reallocated to restricted stock shares		(501	)
Preferred stock added to the denominator under the treasury stock method					10,058,119
Net income available to common stockholders and assumed conversions	$	26,106			25,924,066	$	1.01
Potentially anti-dilutive shares excluded from weighted average shares outstanding					2,347,416

Note 4 - Derivative Instruments

The Company utilizes commodity derivative instruments to reduce its exposure to oil and natural gas price volatility for a significant portion of its estimated production from its proved developed producing oil and natural gas properties. The Company has entered into various derivative contracts with major financial institutions, which, as of June 30, 2018, settle monthly through December 2019.

The Company’s oil and natural gas derivative instruments consist of various instruments, including financially settled oil and natural gas call options, put options, and swaps (including basis swaps), or combinations of these arrangements, which are described below.

• Swaps: The Company receives a fixed price and pays a variable market price to the counterparty for contracted commodity volumes over specified time periods. Basis swaps allow the Company to receive a fixed price differential based on the Argus WTI Cushing index price and pay a variable price differential to the counterparty based on the Argus Mars index price for contracted oil volumes over a specified time period.

• Sold Call Options: A sold call option gives the counterparty the right, but not the obligation, to purchase the underlying commodity volumes from the Company at a specified price (“strike/ceiling

F-13

price”) over a specified time period. At settlement, if the market price is above the fixed ceiling price of the sold call option, the Company pays the counterparty the difference. If the market price settles below the fixed ceiling price of the sold call option, no payment is due from either party.

• Purchased Put Options: A purchased put option gives the Company the right, but not the obligation, to sell the underlying commodity volumes to the counterparty at a specified price (“strike/floor price”) over a specified time period. At settlement, if the market price is below the fixed floor price of the purchased put option, the counterparty pays the Company the difference. If the market price settles above the fixed floor price of the purchased put option, no payment is due from either party.

• Put Spreads: A put spread is a combination of a sold put option and a purchased put option. At settlement, if the market price is below the sold put option strike price, the Company receives the difference between the two strike prices from the counterparty. If the market price settles below the purchased put option strike price but above the sold put option strike price, the Company receives the difference between the purchased put option strike price and the market price from the counterparty. If the market price settles above the purchased put option strike price, no payment is due from either party.

• Collars: A collar contains a purchased put option (“fixed floor price”) and a sold call option (“fixed ceiling price”). At settlement, if the market price is below the fixed floor price, the Company receives the difference between the fixed floor price and the market price from the counterparty. If the market price settles above the fixed ceiling price, the Company pays the counterparty the difference between the market price and the fixed ceiling price.

• Three-way Collars: A three-way collar combines a sold call option (“fixed ceiling price”), a purchased put option (“fixed floor price”), and a sold put option (“fixed subfloor price”). At settlement, if the market price is between the fixed floor price and the fixed subfloor price or is above the fixed ceiling price, the Company receives the fixed floor price from the counterparty or pays the counterparty the market price, respectively. If the market price settles below the fixed subfloor price, the Company receives the market price plus the difference between the fixed floor price and the fixed subfloor price from the counterparty. If the market price settles between the fixed floor price and fixed ceiling price, no payments are due from either party.

F-14

The Company’s oil derivative contracts, other than oil basis swaps, are indexed to the NYMEX WTI. The Company’s oil basis swaps are settled based on the differential between the Argus WTI Cushing and the Argus Mars index prices. The Company had the following outstanding oil derivative contracts in place as of June 30, 2018:

Oil Derivative Contracts	Remainder of 2018		2019
Swaps:
Notional volume (Bbl)		728,040		763,563
Weighted average price ($/Bbl)	$	53.15	$	50.70
Sold Calls:
Notional volume (Bbl)		184,000		—
Weighted average ceiling price ($/Bbl)	$	75.00	$	—
Purchased Puts:
Notional volume (Bbl)		307,317		1,616,001
Weighted average ceiling price ($/Bbl)	$	50.00	$	52.92
Collars:
Notional volume (Bbl)		1,663,040		682,500
Weighted average floor price ($/Bbl)	$	49.59	$	52.00
Weighted average ceiling price ($/Bbl)	$	64.27	$	70.00
Three-way Collars:
Notional volume (Bbl)		301,006		—
Weighted average sub-floor price ($/Bbl)	$	40.00	$	—
Weighted average floor price ($/Bbl)	$	50.00	$	—
Weighted average ceiling price ($/Bbl)	$	65.04	$	—
Put Spreads:
Notional volume (Bbl)		—		268,806
Weighted average sub-floor price ($/Bbl)	$	—	$	45.00
Weighted average floor price ($/Bbl)	$	—	$	55.00
Basis Swaps:
Notional volume (Bbl)		612,000		—
Weighted average price ($/Bbl)	$	4.61	$	—

The Company’s natural gas derivative contracts are indexed to NYMEX HH. The Company had the following outstanding natural gas derivative contracts in place as of June 30, 2018:

Natural Gas Derivative Contracts	Remainder of 2018		2019
Purchased Puts:
Notional volume (MMBtu)		1,758,129		906,861
Weighted average price ($/MMBtu)	$	2.75	$	2.75
Swaps:
Notional volume (MMBtu)		833,135		2,591,700
Weighted average price ($/MMBtu)	$	3.01	$	2.75
Collars:
Notional volume (MMBtu)		—		680,139
Weighted average floor price ($/MMBtu)	$	—	$	3.00
Weighted average ceiling price ($/MMBtu)	$	—	$	3.50

The Company recognizes all of its derivative instruments at fair value as either an asset or as a liability on the accompanying unaudited condensed consolidated balance sheets. The Company has not designated any of its

F-15

derivative instruments as hedges for accounting purposes; therefore, any gains or losses resulting from changes in the fair values of the Company’s outstanding derivatives during the period are recognized in (Loss) gain on derivatives, net in the accompanying unaudited condensed consolidated statements of operations. Additionally, any gains or losses from the settlement of derivative instruments during the period and any proceeds or payments related to early termination of derivative contracts are recognized in (Loss) gain on derivatives, net in the accompanying unaudited condensed consolidated statements of operations.

The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. The Company has elected to net its derivative instrument fair values executed with the same counterparty, pursuant to the ISDA master agreements, which provide for the net settlement over the term of the contract and in the event of the default or termination of the contract.

The Company monitors the creditworthiness of its derivative counterparties, all of which are lenders or affiliates of lenders participating in its Revolving Credit Facility, to determine if any credit risk adjustment is necessary to the fair values of its derivative instruments or if any nonperformance risk exists. The Company’s derivative counterparties are large financial institutions with investment-grade credit ratings; therefore, the Company believes it does not have any significant credit risk associated with its counterparties and does not currently anticipate any nonperformance from its counterparties.

In some cases, the Company might agree to pay a premium on certain of its purchased put option derivative contracts. The Company could agree to pay the premium upfront, in which case the premium payment is recorded as a derivative asset. The value of the premium is considered in the underlying derivative fair value and is adjusted in subsequent periods through (Loss) gain on derivatives, net in the accompanying unaudited condensed consolidated statements of operations. Alternatively, the Company could defer the payment of the premium until the month the applicable derivative contract settles, in which case the Company recognizes the deferred premium obligation net against the derivative instruments fair value asset or liability, pursuant to the ISDA master netting agreements described above. In the period the derivative contract settles, the Company recognizes the deferred premium obligation in (Loss) gain on derivatives, net in the accompanying unaudited condensed consolidated statements of operations.

The following tables present the gross and net fair values of the Company’s derivative instruments, net of any applicable deferred premium obligations recorded on the accompanying unaudited condensed consolidated balance sheets:

	June 30, 2018
	Gross Amounts Recognized			Gross Amounts Offset on the Consolidated Balance Sheets			Net Amounts Presented on the Consolidated Balance Sheets
	(In thousands)
Current assets	$	4,165		$	(4,165	)	$	—
Long-term assets		753			(753	)		—
Current liabilities		(41,897	)		4,165			(37,732	)
Long-term liabilities	$	(4,792	)	$	753		$	(4,039	)

	December 31, 2017
	Gross Amounts Recognized			Gross Amounts Offset on the Consolidated Balance Sheets			Net Amounts Presented on the Consolidated Balance Sheets
	(In thousands)
Current assets	$	2,402		$	(2,402	)	$	—
Long-term assets		371			(371	)		—
Current liabilities		(15,201	)		2,402			(12,799	)
Long-term liabilities	$	(5,465	)	$	371		$	(5,094	)

F-16

As of June 30, 2018 and December 31, 2017, the liability fair values of the Company’s derivatives are presented net of deferred premium obligations of $7.3 million and $5.4 million, respectively.

The following table presents the components of (Loss) gain on derivatives, net on the accompanying unaudited condensed consolidated statements of operations and statements of cash flows. Total cash (paid) received for derivative settlements, net reflects the gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price for those contracts. Any proceeds or payments related to early termination of derivative contracts and any upfront premiums paid for new derivative contracts during the period are included in the total cash (paid) received for derivative settlements, net. Additionally, deferred premium obligations paid reflect the cash premium payments associated with derivative contracts settled during the period. Total non-cash (loss) gain on derivatives, net represents the changes in the fair values of derivative instruments outstanding at the end of the period and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.

	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018			2017
	(In thousands)
Cash (paid) received for derivative settlements, net:
Oil	$	(8,774	)	$	13,152	$	(13,916	)	$	15,365
Natural gas		(305	)		110		145			645
Total cash (paid) received for derivative settlements, net		(9,079	)		13,262		(13,771	)		16,010
Non-cash (loss) gain on derivatives:
Oil		(14,734	)		3,999		(22,671	)		21,973
Natural gas		(84	)		1,066		(1,207	)		3,158
Total non-cash (loss) gain on derivatives, net		(14,818	)		5,065		(23,878	)		25,131
(Loss) gain on derivatives, net	$	(23,897	)	$	18,327	$	(37,649	)	$	41,141

Total cash (paid) received for derivative settlements, net includes deferred premium obligations paid for oil and natural gas derivative contracts of $0.8 million and $1.7 million for the three and six months ended June 30, 2018, respectively, and $0.4 million and $0.5 million for the three and six months ended June 30, 2017, respectively.

Note 5 - Fair Value Measurements

Certain of the Company’s assets and liabilities are carried at fair value and measured either on a recurring or non-recurring basis. The Company’s fair value measurements are based either on actual market data or assumptions that other market participants would use in pricing an asset or liability in an orderly transaction, using the valuation hierarchy prescribed by GAAP.

The GAAP valuation hierarchy categorizes assets and liabilities measured at fair value into one of three levels depending on the observability of inputs used to determine fair value. The three levels of the fair value hierarchy are as follows:

• Level 1: Unadjusted quoted prices for identical assets or liabilities in active markets.

• Level 2: Observable inputs other than Level 1 inputs. These include: quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets which are not active, or inputs that are corroborated by observable active market data.

• Level 3: Unobservable inputs for which little or no market data exists.

F-17

The classification of an asset or liability within the fair value hierarchy is based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement of an asset or liability requires judgment and may affect the valuation of the fair value asset or liability and its placement within the fair value hierarchy. There have been no transfers between fair value hierarchy levels.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Commodity derivative contracts. The fair values of the Company’s derivative instruments are measured on a recurring basis using a third-party industry-standard pricing model that considers various inputs such as quoted forward commodity prices, discount rates, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant data. These significant inputs are observable in the current market or can be corroborated by observable active market data and are therefore considered Level 2 inputs within the fair value hierarchy.

11.00% Senior notes due 2023. The Company has elected the fair value option to account for the 2023 Notes and all of its features; therefore, the 2023 Notes are recorded at their fair value and the change to the fair value is recorded as Loss on fair value of 11.00% Senior notes due 2023. The fair value of the Company’s 2023 Notes is measured on a recurring basis and is based on unadjusted quoted prices for an identical liability in an active market, which is considered a Level 1 input. Refer to Note 8 - Long-term Debt for a discussion of the Company’s 2023 Notes.

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 using the fair value hierarchy:

	Fair Value Measurement as of June 30, 2018
	Total			Level 1			Level 2			Level 3
	(In thousands)
Assets:
Commodity derivative contracts	$	4,918		$	—		$	4,918		$	—
Liabilities:
Commodity derivative contracts	$	(46,689	)	$	—		$	(46,689	)	$	—
11.00% Senior notes due 2023	$	(352,830	)	$	(352,830	)	$	—		$	—

	Fair Value Measurement as of December 31, 2017
	Total			Level 1		Level 2			Level 3
	(In thousands)
Assets:
Commodity derivative contracts	$	2,773		$	—	$	2,773		$	—
Liabilities:
Commodity derivative contracts	$	(20,666	)	$	—	$	(20,666	)	$	—

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Class A Common Stock. The per share fair value of the Company’s $0.001 par value Class A common stock (“Class A Common Stock”) is estimated on a non-recurring basis at the grant date of the shares by a third party using an option pricing model (“OPM”). The OPM estimates the per share fair value of the Company’s Class A Common Stock on a minority, marketable basis, and applies a discount for lack of marketability to account for the illiquidity of the Company’s Class A Common Stock. The OPM allocates the Company’s total equity value to the various classes of equity in the Company’s capital structure, treating the Class A Common Stock, $0.001 par value Class B common stock (“Class B Common Stock”), and $0.001 par value Series A convertible perpetual preferred stock (“Series A Preferred Stock”) as options on the entity’s enterprise value and captures the option-like characteristics of common stock for entities whose common stock is a small portion of the total capital structure.

F-18

The significant inputs used in the OPM include the timing of an expected liquidity event date, equity volatility, risk-free rate, and an estimate of the Company’s total equity value as of the grant date of the shares. These significant inputs are based on and sensitive to unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. The estimates of fair value of the Company’s Class A Common Stock are highly complex and subjective, incorporating significant judgments and estimates in the fair value assumptions. Refer to Note 10 - Stock-based Compensation for a discussion of the Company’s Restricted Stock.

Fair Value of Other Financial Instruments

Cash and cash equivalents, restricted cash and restricted cash equivalents, accounts receivable, and accounts payable. The carrying amounts of the Company’s cash and cash equivalents, restricted cash and restricted cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.

Other long-term debt. The carrying amounts of long-term debt associated with any borrowings outstanding under the Company’s variable interest rate Revolving Credit Facility and Second Lien Term Loan approximates fair value based on borrowing rates available to the Company for bank loans with similar terms and maturities, which are observable in the current market and are therefore considered Level 2 inputs within the fair value hierarchy. As of June 30, 2018 and December 31, 2017, there were no indicators of change in the Company’s market spread.

Note 6 - Notes Payable

On February 24, 2017, the Company entered into an agreement to purchase a drilling rig and related equipment from Helmerich & Payne International Drilling Co. (“H&P”) for a total purchase price of $18.0 million. The Company paid H&P cash consideration of $8.0 million, with the remaining $10.0 million to be paid in quarterly installments of $1.7 million, beginning July 1, 2017. The Company recorded the fair value of the installment payments as a note payable at an effective interest rate of 4.8% and is amortizing the discount into Interest expense on the accompanying unaudited condensed consolidated statements of operations over the term of the installment period. During the three and six months ended June 30, 2018, the Company paid quarterly installments of $1.7 million and $3.3 million, respectively. As of June 30, 2018 and December 31, 2017, the Company had a liability of $3.3 million and $6.5 million, respectively, for the remaining installment payments due to H&P.

On May 15, 2017, the Company entered into a note payable for its commercial insurance program, which required an initial installment of $1.9 million and nine monthly installments of principal and interest of $0.9 million, beginning on June 15, 2017, at an interest rate of 2.7%. The Company paid monthly principal and interest installments of $1.7 million during the three and six months ended June 30, 2018 and $0.9 million during the three and six months ended June 30, 2017. As of December 31, 2017, the outstanding balance of this note payable was $1.7 million and the note was paid in full as of June 30, 2018.

Note 7 - Asset Retirement Obligations

The Company’s asset retirements obligations (“ARO”) relates to future P&A costs on its oil and natural gas properties and related facility disposals. The Company records a liability at the fair value for ARO when it is incurred and the associated ARO cost is capitalized by increasing the carrying value of the related oil and natural gas properties. In subsequent periods, if the estimate of the ARO liability changes, the Company records an adjustment to both the ARO liability and the oil and natural gas properties carrying value. Over time, the liability accretes for the change in its present value, while the capitalized cost depletes over the useful life of the related asset. Upon settlement of the ARO, the Company either settles the obligation for its recorded liability amount or incurs a gain or loss, which is included in capitalized oil and natural gas properties.

F-19

The following table presents the change in the Company’s ARO during the six months ended June 30, 2018:

	(In thousands)
Asset retirement obligations as of January 1, 2018	$	276,084
Liabilities settled		(3,149	)
Revisions of previous estimates		6,655
Accretion expense		17,136
Asset retirement obligations as of June 30, 2018		296,726
Less: current portion of asset retirement obligations		(26,751	)
Asset retirement obligations, less current portion as of June 30, 2018	$	269,975

Revisions of previous estimates during the six months ended June 30, 2018 are attributable to changes in estimated cash flows, working interests, and planned timing of P&A activities.

Note 8 - Long-term Debt

The Company’s outstanding long-term debt balances consist of the following for the periods indicated:

	June 30, 2018		December 31, 2017
	(In thousands)
11.00% Senior notes due 2023	$	325,000	$	—
Fair value adjustment		27,830		—
11.00% Senior notes due 2023, at fair value		352,830		—
Revolving credit facility, weighted average interest rate of 5.11% as of December 31, 2017		—		95,000
Second lien term facility, weighted average interest rate of 12.85% as of December 31, 2017		—		202,500
Other long-term debt		—		297,500
Less: unamortized deferred financing costs and debt discount		—		(5,305	)
Other long-term debt, net		—		292,195
Total long-term debt, net	$	352,830	$	292,195

Revolving Credit Facility

In 2014, the Company entered into an agreement with a syndicate of banks and established the Revolving Credit Facility, which was amended and restated in 2016 and which is secured by substantially all of the Company’s assets on a first lien basis. As part of the 2018 Refinancing Transactions, the Company amended the Revolving Credit Facility agreement to extend the maturity date to January 26, 2022 and increase the initial borrowing base to $231.3 million (with lender commitments of $250.0 million). The borrowing base is subject to semi-annual redetermination, based on an assessment of the value of the Company’s proved reserves as determined by a reserve report. As a result of the semi-annual redetermination, the borrowing base was increased to $275.0 million in June 2018. The Revolving Credit Facility has a maximum line of credit to $500.0 million.

Also as part of the 2018 Refinancing Transactions, the Company used a portion of the net proceeds from the 2023 Notes Offering to repay all the amounts outstanding under its Revolving Credit Facility. As a result, the Company did not have any outstanding borrowings under its Revolving Credit Facility as of June 30, 2018. As of December 31, 2017, the Company had outstanding borrowings of $95.0 million under its Revolving Credit Facility and $3.6 million in outstanding letters of credit. As of June 30, 2018, the Company had availability of $271.4 million (after giving effect to $3.6 million of outstanding letters of credit to collateralize its oil and natural gas transportation agreements and P&A obligations) under its Revolving Credit Facility.

F-20

As amended, borrowings under the Revolving Credit Facility bear interest at one of the following rates, as selected by the Company: (i) the bank’s prime rate in effect, adjusted by an applicable margin of 1.75%–2.75%; or (ii) the London Interbank Offered Rate, adjusted by an applicable margin of 2.75%–3.75%. The Company may elect to convert outstanding borrowings to a different type and interest rate. The Company recognized $0.3 million and $1.1 million in interest expense during the three and six months ended June 30, 2018, respectively, and $1.9 million and $4.1 million during the three and six months ended June 30, 2017, respectively. Refer to Note 2 - Basis of Presentation and Summary of Significant Accounting Policies - Debt Issuance Costs for further discussion of the 2018 Refinancing Transaction costs.

The Revolving Credit Facility, as amended, contains certain covenants, as defined in the amended agreement, including a maximum ratio of total funded debt to EBITDAX, a maximum ratio of total secured debt to EBITDAX, and a minimum ratio of current assets to current liabilities. Other restrictive covenants include, but are not limited to, limitations on the Company’s ability to incur indebtedness, declare and pay dividends, make loans or investments, enter into certain hedging agreements, materially change its business, or undergo a change of control.

Second Lien Term Loan

In 2014, the Company also established the Second Lien Term Loan, which was secured by a second lien on substantially all of the assets owned by the Company and was subject to the limitations of the Revolving Credit Facility. As part of the 2018 Refinancing Transactions, the Company used a portion of the net proceeds from the 2023 Notes Offering to repay all of the amounts outstanding (including accrued interest and premiums) under the Second Lien Term Loan and terminated the Second Lien Term Loan at that time. As a result, the Company did not have any outstanding borrowings under its Second Lien Term Loan as of June 30, 2018. The Company had outstanding borrowings of $202.5 million under its Second Lien Term Loan as of December 31, 2017. Following the 2018 Refinancing Transactions, the Company did not have any outstanding borrowings under its Second Lien Term Loan, and therefore, did not recognize any interest expense related to its Second Lien Term Loan during the three months ended June 30, 2018. The Company recognized $3.3 million in interest expense during the six months ended June 30, 2018 and $6.7 million and $13.4 million during the three and six months ended June 30, 2017, respectively.

11.00% Senior Notes Due 2023

On February 15, 2018, the Company completed a private offering of the $325.0 million aggregate principal amount of 11.00% senior secured second lien notes due 2023. The 2023 Notes were issued by EnVen GoM and co-issued by EnVen GoM’s wholly-owned subsidiary, EnVen Finance Corporation. The Company received net proceeds of $317.0 million, after deducting initial purchaser fees and offering expenses of $8.0 million. The 2023 Notes will mature on February 15, 2023 and are initially guaranteed by the Company and its domestic subsidiaries that guarantee the Revolving Credit Facility. The 2023 Notes and the related guarantees are secured by second-priority liens on the Company’s and the guarantors’ assets that secure all of the indebtedness under the Revolving Credit Facility, subject to certain exceptions. Interest on the 2023 Notes accrues from February 15, 2018, the date of issuance, and is paid semi-annually in cash in arrears on February 15th and August 15th of each year, beginning August 15, 2018.

The indenture that governs the 2023 Notes contains certain covenants, which are customary with respect to non-investment grade debt securities, including limitations on the Company’s ability to incur and guarantee additional indebtedness, issue certain preferred stock or similar equity securities, pay dividends or make other distributions on, or redeem or repurchase, capital stock and make other restricted payments, prepay, redeem or repurchase certain debt, enter into certain types of transactions with affiliates, make loans or investments, enter into agreements restricting our subsidiaries’ ability to pay dividends, create liens and sell certain assets or merge with or into other companies.

F-21

The 2023 Notes indenture also contains certain put and call features that were analyzed for potential bifurcation as embedded derivatives in accordance with ASC 815. One of these features grants the Company an option, for up to two years from the 2023 Notes issuance date, to redeem a portion of the 2023 Notes at a premium of the face value (plus any accrued unpaid interest) if it completes an equity offering (“Equity Offering Redemption Option”). The Company has analyzed the Equity Offering Redemption Option and has determined it is not clearly and closely related to the risks and rewards of the 2023 Notes and requires bifurcation. Due to this embedded derivative feature, the Company has elected to account for the 2023 Notes and all of its features using the fair value option, in accordance with ASC 815. The Company recorded the 2023 Notes at their fair value on the accompanying unaudited condensed consolidated balance sheet as of June 30, 2018 and the change in fair value as Loss on fair value of 11.00% Senior notes due 2023 on the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2018. At the end of each reporting period, the Company will remeasure the fair value of the 2023 Notes and will recognize the changes in fair value as a gain or loss on fair value of 11.00% Senior notes due 2023.

Additionally, due to the fair value option election in accordance with ASC 815, the Company expensed the debt issuance costs of $8.0 million associated with the 2023 Notes and modification related costs of $2.7 million associated with the Second Lien Term Loan as Interest expense on the accompanying unaudited condensed consolidated statement of operations for the six months ended June 30, 2018. Additionally, the Company recognized $8.9 million and $13.2 million, respectively, of interest per the contractual rate as Interest expense on the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2018. Refer to Note 2 - Basis of Presentation and Summary of Significant Accounting Policies - Debt Issuance Costs for a discussion of the 2018 Refinancing Transaction costs.

Note 9 - Stockholders’ Equity

Series A Preferred Stock

On December 30, 2016, the Company issued 6,159,596 shares of its Series A Preferred Stock to selected institutional investors for $12.00 per share, resulting in net proceeds of $72.7 million, including underwriter discounts and offering expenses of $1.2 million (the “Series A Preferred Stock Offering”). The net proceeds of the Series A Preferred Stock Offering were used to fund the acquisition of 100% working interest in the U.S. Gulf of Mexico Green Canyon blocks 158 and 202 (“Brutus”) and 248 (“Glider”) fields, including the Brutus tension-leg platform, a subsea facility, 16 wells, and 2 transportation pipelines from Shell Offshore Inc. (“Shell”) for a total adjusted consideration of $238.7 million (the “Shell Acquisition”). In connection with the Shell Acquisition, the Company issued an additional 3,708,334 shares of Series A Preferred Stock to Shell in exchange for $44.5 million of additional purchase price consideration (“Shell Series A Preferred Stock Offering”).

The holders of Series A Preferred Stock are entitled to receive dividends, at the election of the Company’s board of directors (the “Board”), in cash or in Paid-in-kind Series A Preferred Stock (“PIK Share”), which are cumulative from the issue date and payable quarterly, in arrears, beginning on December 31, 2016. Historically, the Board has elected to declare PIK Share dividends on a quarterly basis. The Series A Preferred Stock also contains several conversion, redemption, and liquidation features, none of which have been triggered or exercised as of June 30, 2018.

At the end of each reporting period and each time PIK Share dividends are declared, the Company must evaluate if there is a beneficial conversion feature related to the PIK Share dividends by comparing the fair value of the Company’s Class A Common Stock to the original issue price of $12.00 per share. For the three and six months ended June 30, 2018, the Company recognized a beneficial conversion feature associated with the PIK Share dividends of $4.9 million and $7.3 million, respectively, which is included in the Series A preferred stock dividends line item on the accompanying unaudited condensed consolidated statements of operations. The Company did not recognize a beneficial conversion feature associated with the PIK Share dividends for the three and six months ended June 30, 2017.

F-22

The following table summarizes the components of the Series A preferred stock dividends presented on the accompanying unaudited condensed consolidated statements of operations for the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(In thousands)
Series A preferred stock dividends - paid-in-kind	$	4,336	$	4,506	$	8,516	$	8,898
Series A preferred stock dividends - beneficial conversion feature		4,923		—		7,278		—
Total Series A preferred stock dividends	$	9,259	$	4,506	$	15,794	$	8,898

On March 14, 2018, the Company repurchased 2,149,217 shares of its Series A Preferred Stock from Shell at $12.00 per share, for a total price of $25.8 million. Additionally, on March 28, 2018, certain of the Company’s equity investors, including Bain Capital Credit (“Bain”) and Adage Capital Partners, L.P., repurchased the remaining 2,229,812 shares held by Shell (including the rights to the PIK Share dividends issued on March 31, 2018) at $12.00 per share. As a result of this repurchase, Shell no longer owns any of the Company’s Series A Preferred Stock. Refer to Note 14 - Related Party Transactions for further discussion of the Company’s relationship with Shell as of and during the six months ended June 30, 2018.

Non-controlling Interest

The Company’s majority ownership interest percentage of EnVen GoM is based on the proportionate amount of its $0.001 par value Class B common stock outstanding to the total shares outstanding, inclusive of Class A Common Stock, Series A Preferred Stock, and PIK Share dividends. Therefore, the Non-controlling Interest percentage changes if and when shares of Class A Common Stock, Series A Preferred Stock, and PIK Share dividends are issued. As of June 30, 2018 and December 31, 2017, the Company owned approximately 88.7% and 89.2%, respectively, of the interest in EnVen GoM and the Non-controlling Interest was 11.3% and 10.8%, respectively.

Note 10 - Stock-based Compensation

Incentive Award Plan

The Company has established the EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan (the “Plan”) which authorizes the granting of Restricted Stock, stock options, performance bonuses, and other incentive awards to eligible employees, consultants, and members of the Company’s Board. The Company is authorized to award up to 2,583,301 shares of the Company’s Class A Common Stock pursuant to the Plan. As of June 30, 2018, the Company had 150,044 shares of the Company’s Class A Common Stock available for grant under the Plan. As of June 30, 2018, all incentive awards granted under the Plan have been to employees or members of the Company’s Board.

Restricted stock awards and units. The Company awards both time-vested and performance-based Restricted Stock subject to terms, restrictions, and vesting requirements defined in the restricted stock agreements. Time-vested Restricted Stock contains a vesting period subject to the Restricted Stock holder continuing employment or service and generally vests in equal installments on each of the second and third anniversaries of the grant date. Performance-based Restricted Stock vests only if the Company achieves certain performance goals during a predetermined performance period and the Restricted Stock holder remains employed or continues service during the vesting period.

The Company’s Restricted Stock does not have any post-vesting restrictions, therefore, the fair value of each share of Restricted Stock on the date of grant is determined based on the per share fair value of the Company’s

F-23

Class A Common Stock on a minority, non-marketable basis. The per share fair value of the Company’s Class A Common Stock is estimated at the grant date of the shares by a third party using an OPM. The inputs to the OPM include assumptions regarding the timing of an expected liquidity event date, equity volatility, risk-free rate, expected dividend yield, and an estimate of the Company’s total equity value as of the grant date of the shares. The assumed timing of an expected liquidity event is based on management’s estimate. As there is currently no active market for the Company’s Class A Common Stock, the Company’s expected equity volatility is determined using the historical volatility of a publicly traded set of peer companies. The risk-free interest rate utilized is based on the interpolated yields of the U.S. Treasury bonds with maturities that commensurate the timing of an expected liquidity event date. The Company has not historically declared or paid Class A Common Stock cash dividends and does not plan to, therefore, the Company does not expect a dividend yield. Refer to Note 5 - Fair Value Measurements for a discussion of the fair value of the Company’s Class A Common Stock.

The Company utilized OPM valuations using the following assumptions to determine the grant date fair value of the Company’s Restricted Stock granted during the six months ended June 30, 2018:

Risk free interest rate	1.94	%
Expected stock price volatility	55.0	%
Expected dividend yield	—	%

The following table presents the Company’s Restricted Stock activity during the six months ended June 30, 2018:

	Restricted Stock			Weighted Average Grant     Date Fair Value
Non-vested as of January 1, 2018		1,544,771		$	11.95
Granted		20,000		$	25.62
Vested		(87,378	)	$	10.68
Non-vested as of June 30, 2018		1,477,393		$	12.21

The aggregate fair value of the Restricted Stock that vested during the six months ended June 30, 2018 was $1.6 million.

At the time of vesting, Restricted Stock holders may elect to have the Company forfeit a portion of their vested Restricted Stock, based on the Company’s Class A Common Stock fair market value, on their behalf to satisfy their tax withholding requirements. The Restricted Stock that vested during the six months ended June 30, 2018 includes 27,704 shares withheld by the Company on behalf of Restricted Stock holders to satisfy $0.4 million of tax withholding requirements. Class A Common Stock withheld or canceled in connection with tax withholding requirements will be available for new grants under the Plan.

The Company recognizes compensation expense related to time-vested Restricted Stock based on a straight-line basis over the vesting period based on the fair value of the Restricted Stock on the date of grant. The Company recognized compensation expense related to time-vested Restricted Stock of $1.6 million and $3.1 million during the three and six months ended June 30, 2018, respectively, and $1.3 million and $1.9 million during the three and six months ended June 30, 2017, respectively. As of June 30, 2018, there was $6.4 million of unrecognized compensation expense related to time-vested Restricted Stock, which is expected to be recognized over a weighted average remaining service period of 0.96 years.

The Company recognizes the compensation expense related to performance-based Restricted Stock at the time the performance condition is deemed probable of occurring based on the fair value of the Restricted Stock on the date of grant. As of June 30, 2018, there was $5.8 million of unrecognized compensation expense related to performance-based Restricted Stock. The Company continuously assesses the probability that the performance conditions related to the performance-based Restricted Stock will be achieved and there have been no changes to the probability of the performance conditions during the six months ended June 30, 2018.

F-24

Stock options. The Company also awards stock options, which represent the right to purchase Class A Common Stock at a specified price (“Stock Option”). Generally, Stock Options vest in equal installments on each of the first three anniversaries of the grant date. All outstanding Stock Options have an exercise price of $10.00 and expire in 2025.

The following table presents the Company’s Stock Option activity during the six months ended June 30, 2018:

	Stock Options		Weighted Average Grant     Date Fair Value		Weighted Average     Contractual Term
Outstanding as of January 1, 2018		682,650	$	4.39
Outstanding as of June 30, 2018		682,650	$	4.39		7.36 years
Vested and exercisable as of June 30, 2018		455,100				7.36 years

The Company recognizes compensation expense related to Stock Options on a straight-line basis over the vesting period based on the fair value of the Stock Options on the date of grant. The Company recognized compensation expense related to Stock Options of $0.3 million and $0.6 million during the three and six months ended June 30, 2018, respectively, and $0.3 million and $0.6 million during the three and six months ended June 30, 2017, respectively. As of June 30, 2018, there was $0.4 million of total unrecognized compensation expense related to outstanding Stock Options, which is expected to be recognized over a weighted average remaining service period of 0.19 years.

Note 11 - Commitments and Contingencies

Legal Proceedings

From time to time, the Company could be subject to legal actions and claims arising in the ordinary course of business. It is the opinion of management that the outcome of these matters will not have a material adverse effect on the Company’s financial position or results of operations.

Asset Retirement Obligations

Marathon Acquisitions. In connection with the Company’s acquisition of ownership interests in and the operatorship of the U.S. Gulf of Mexico Ewing Bank blocks 873, 917, and 963, including the Lobster platform (collectively, “Lobster”), a subsea facility and 29 wells and ownership interest in the Vioska Knoll blocks 742, 786, and 830, including 23 wells, on December 18, 2015 from Marathon Oil Company, the Company is required to deposit approximately $100.0 million into escrow accounts to use for future P&A obligation costs assumed in the acquisition. On the closing date of the acquisition, the Company deposited $30.1 million into escrow to fully fund one of the P&A obligations.

The remaining funding obligation began in January 2017 and is being funded quarterly with a percentage of the net revenues from the acquired properties until the relevant account reaches $70.0 million. As of June 30, 2018 and December 31, 2017, the escrow balance was $12.3 million and $5.5 million, respectively, which is recorded in Restricted cash on the accompanying unaudited condensed consolidated balance sheets.

Other obligations. The Bureau of Ocean Management and certain third-parties require the Company to post supplemental and performance bonds as a means to ensure its decommissioning obligations, such as the plugging of wells, the removal of platforms and other offshore facilities, the abandonment of offshore pipelines, and the clearing of the seafloor of obstructions. The Company enters into arrangements with surety companies who provide such bonds on the Company’s behalf. The Company may be required to provide cash collateral to support the issuance of these bonds and usually pays an annual premium in exchange for the surety’s financial strength to extend the credit. As of June 30, 2018 and December 31, 2017, the Company provided surety companies with cash collateral of approximately $41.1 million and $41.0 million, respectively, which is recorded

F-25

in Restricted cash on the accompanying unaudited condensed consolidated balance sheets. The surety bond premium is recognized in the Prepaid assets line item on the accompanying unaudited condensed consolidated balance sheets and amortized over the life of the surety bond into Interest expense on the accompanying unaudited condensed consolidated statements of operations. The Company amortized surety bond premiums of $3.7 million and $7.3 million during the three and six months ended June 30, 2018, respectively, and $3.1 million and $7.1 million during the three and six months ended June 30, 2017, respectively. During the three and six months ended June 30, 2018, the Company paid $0.2 million and $1.6 million, respectively, related to surety bond premiums and $2.2 million and $15.9 million during the three and six months ended June 30, 2017, respectively. The increase in payments during the six months ended June 30, 2017 was due to the timing of premium payments for obligations related to assets acquired in the Shell Acquisition.

Note 12 - Income Taxes

On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) significantly revised U.S. federal corporate income tax law by, among other things, reducing the U.S. federal corporate income tax rate to 21%, limiting the tax deduction for interest expense to 30% of adjusted taxable income, allowing immediate expensing for certain new investments, and, effective for net operating losses arising in taxable years beginning after December 31, 2017, eliminating net operating loss carrybacks, permitting indefinite net operating loss carryforwards, and limiting the use of net operating loss carryforwards to 80% of current year taxable income.

The Company estimates its annual effective income tax rate on a quarterly basis based on current annual forecasted operating results. Unusual or infrequent items unrelated to current year ordinary income are recognized as discrete items in the period in which they are identified. The quarterly income tax provision is comprised of tax on ordinary income at the most recent estimated annual effective tax rate and is adjusted by the tax effect of these discrete items. Each quarter, the Company updates these rates and records a cumulative adjustment to income tax expense by applying the updated rates to the year-to-date-pre-tax income excluding discrete items.

The Company has a net deferred tax asset with respect to its investment in the underlying partnership, and this net deferred tax asset is subject to a full valuation allowance. Any temporary differences between the book and tax earnings of the underlying partnership that are allocated to the Company affect the gross deferred tax asset balance. However, since the valuation allowance is applied to the gross deferred tax asset, the temporary differences do not produce a deferred tax benefit or deferred tax expense which would otherwise offset the current tax effect of temporary differences between book and taxable income. Along with the attribution of portions of the Company’s consolidated book income to non-controlling interest, this primarily produces the variations between the Company’s effective tax rate and the U.S. federal statutory tax rate of 21%.

The Company’s effective tax rate for the three and six months ended June 30, 2018 was 0.0% and 10.7%, respectively. For the three and six months ended June 30, 2017, the Company’s effective tax rate was 57.7% and 26.9%, respectively. The overall changes in the Company’s effective tax rates for the three and six months ended June 30, 2018 compared to the same periods of 2017 are due primarily to changes in income allocations from the underlying partnership to the Company, partially offset by the decrease in the federal statutory rate from 35% to 21% due to the Tax Act.

The Company has considered all available positive and negative evidence related to the realization of its net deferred tax asset. The net deferred tax asset, in the judgment of management, is not more likely than not to be realized. The Company continues to maintain a full valuation allowance against its net deferred tax asset as of June 30, 2018.

F-26

Note 13 - Supplemental Cash Flow Information

The following tables present a reconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents reported on the accompanying unaudited condensed consolidated statements of cash flows:

	June 30,
	2018		2017
	(In thousands)
Cash and cash equivalents	$	91,515	$	4,458
Current portion of restricted cash(1)		9,398		9,532
Long-term portion of restricted cash(1)		74,088		65,877
Total cash, cash equivalents, restricted cash, and restricted cash equivalents	$	175,001	$	79,867

	December 31, 2017
	(In thousands)
Cash and cash equivalents	$	28,848
Current portion of restricted cash(1)		6,789
Long-term portion of restricted cash(1)		69,783
Total cash, cash equivalents, restricted cash, and restricted cash equivalents	$	105,420

(1) Represents restricted cash held for future P&A obligations, refer to Note 11 - Commitments and Contingencies for further discussion of these P&A obligations.

The following table presents non-cash investing and financing activities and supplemental disclosure relating to cash paid for interest and income taxes for the periods indicated:

	Six Months Ended June 30,
	2018			2017
	(In thousands)
Non-cash investing and financing activities:
Changes in asset retirement obligations	$	6,655		$	(320	)
Expenditures for property and equipment in accrued liabilities		(1,991	)		12,865
Notes payable issued for property and equipment		—			9,550
Series A preferred stock dividends - paid-in-kind		(8,516	)		(5,497	)
Series A preferred stock dividends - paid-in-kind - Related party		—			(3,401	)
Series A preferred stock dividends - beneficial conversion feature	$	(7,278	)	$	—
Supplemental disclosure:
Interest paid on debt	$	5,093		$	8,448
Income taxes paid	$	23,178		$	—

Note 14 - Related Party Transactions

Redemption Rights

Pursuant to the terms of the amended and restated limited liability company agreement of EnVen GoM, the members of EnVen GoM have the right, at their sole discretion, to redeem their interests for cash, or at the option of the Company, shares of Class A Common Stock at an exchange ratio of one share of Class A Common Stock for each interest exchanged (“Redemption Rights”). If the members exercise their Redemption Rights, the Company’s interest in EnVen GoM will correspondingly increase. As of June 30, 2018, there have been no exercises of Redemption Rights.

F-27

Tax Receivable Agreement

On October 30, 2015, Energy Ventures GoM Holdings, LLC entered into an agreement to sell 13,732,925 units in a private offering, at a price of $10.00 per unit, to selected institutional investors (the “2015 Equity Offering”). In connection with the 2015 Equity Offering, the Company entered into a Tax Receivable Agreement (“TRA”) with Equity Holdings, LLC (“Equity Holdings”), as holder of all limited liability company interests of EnVen GoM not held by the Company. Equity Holdings has the right to convert its limited liability company interests in EnVen GoM into Class A Common Stock of the Company. Upon such conversions, applicable income tax rules provide certain incremental deductions for tax depreciation, depletion, and amortization to the Company resulting from the conversions. Pursuant to the TRA, the Company is required to remit 85% of the cash tax savings, determined on a with-and-without basis, to Equity Holdings should it convert limited liability company interests in EnVen GoM into Class A Common Stock of the Company or payments are accelerated pursuant to the terms of the TRA. The Company has the right to terminate the TRA early, in which case, it would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the TRA, calculated based on certain assumptions and deemed events as set forth in the TRA. In addition, payments due under the TRA will be similarly accelerated following certain mergers or other changes of control. The TRA will remain in effect until (a) Equity Holdings or any successor holders exchange all LLC Units of EnVen GoM pursuant to the Redemption Rights and the payment of all amounts required to be paid under the Tax Receivable Agreement or (b) the TRA is early terminated pursuant to its terms.

The Company’s unaudited condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017 do not reflect a liability for amounts that could become payable pursuant to the TRA in connection with conversions of limited liability company interests in EnVen GoM into Class A Common Stock of the Company. As amounts payable pursuant to the TRA only arise in connection with conversions of limited liability company interests in EnVen GoM into Class A Common Stock of the Company, the criteria for reporting a liability on the Company’s unaudited condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017 have not been met until such conversions have occurred. To date, no such conversions have occurred and, accordingly, no amounts are reflected as a liability on the unaudited condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017. Additionally, the Company cannot be certain at this time when Equity Holdings may elect to convert its interests into shares of the Company.

Shell Offshore Inc.

On December 30, 2016, the Company completed the Shell Acquisition and the Shell Series A Preferred Stock Offering which resulted in the issuance of 3,708,334 shares of Series A Preferred Stock to Shell for $44.5 million of acquisition purchase price consideration. As of December 31, 2017, the Company had issued 4,298,433 shares of Series A Preferred Stock to Shell, including 590,099 PIK Share dividends, which resulted in Shell owning more than 10% of the Company’s voting rights and qualified Shell as a principal owner of the Company, as defined in ASC Topic 850, Related Party Disclosures. Additionally, during the year ended December 31, 2017, Shell was a major purchaser of the Company’s oil production. Due to these circumstances, the Company had a related party relationship with Shell as of and during the year ended December 31, 2017.

On March 14, 2018, the Company repurchased 2,149,217 shares of its Series A Preferred Stock from Shell at $12.00 per share, for a total price of $25.8 million. Additionally, on March 28, 2018, certain of the Company’s equity investors repurchased the remaining 2,229,812 shares held by Shell (including the rights to the PIK Share dividends issued on March 31, 2018) at $12.00 per share. As a result of this repurchase, Shell no longer owns any of the Company’s Series A Preferred Stock or has any voting interest and, as such, Shell no longer qualifies as a principal owner of the Company or qualifies as a related party as of March 15, 2018.

Due to these circumstances, the Company has identified and stated its transactions with Shell as related party transactions on the face of the accompanying unaudited condensed consolidated balance sheet as of December 31, 2017, the accompanying unaudited condensed consolidated statements of operations for the six months ended June 30, 2018 and 2017 and the three months ended June 30, 2017, and the accompanying unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2018 and 2017.

F-28

Bain Capital Credit

As of June 30, 2018, entities affiliated with Bain hold 46.9% of the Company’s voting interest and three members of the Company’s Board are affiliated with Bain. Additionally, immediately following the 2018 Refinancing Transactions, entities affiliated with Bain held 11.3% of the Company’s 2023 Notes.

Note 15 - Subsequent Events

The Company has evaluated subsequent events from the balance sheet date of June 30, 2018 through August 13, 2018, the date at which these unaudited condensed consolidated financial statements were available to be issued and has determined there are no other events to disclose.

F-29

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of EnVen Energy Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of EnVen Energy Corporation and subsidiaries (the Company) as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in equity and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2018.

Houston, Texas

May 30, 2018

F-30

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

(In thousands, except share information)

	December 31, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	28,848		$	28,477
Current portion of restricted cash		6,789			9,532
Accounts receivable:
Oil, natural gas, and NGL sales		9,483			5,149
Oil, natural gas, and NGL sales - Related party		44,774			20,502
Joint interest and other		14,048			7,111
Prepaid expenses		21,584			11,604
Total current assets		125,526			82,375
Property and equipment:
Oil and natural gas properties, full cost method, including $12,648 and $6,328 of unevaluated properties not being amortized as of December 31, 2017 and December 31, 2016, respectively		1,058,539			951,003
Other property and equipment		4,212			3,832
Less: accumulated depreciation, depletion, and amortization		(371,261	)		(200,910	)
Property and equipment, net		691,490			753,925
Notes receivable		13,982			12,408
Notes receivable - Related party		34,095			31,499
Restricted cash		69,783			60,094
Other assets		6,357			8,969
Other assets - Related party		1,808			1,797
Total assets	$	943,041		$	951,067
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	26,471		$	8,555
Accounts payable - Related party		621			—
Accrued liabilities		38,610			21,148
Revenue and royalties payable		9,839			7,461
Revenue and royalties payable - Related party		7,226			26
Joint owner advances payable		578			516
Derivative liabilities		12,799			4,051
Notes payable		8,308			2,677
Asset retirement obligations		21,828			44,228
Current portion of long-term debt		—			11,250
Income tax payable		14,095			—
Total current liabilities		140,375			99,912
Natural gas imbalances		710			1,087
Derivative liabilities		5,094			815
Notes payable, less current portion		26			73
Asset retirement obligations, less current portion		254,256			243,472
Long-term debt, net of current portion		292,195			368,514
Total liabilities		692,656			713,873
Commitments and contingencies (Note 14)
Stockholders’ equity:
Series A convertible perpetual preferred stock, $0.001 par value, 25,000,000 shares authorized
7,139,759 and 6,162,134 shares issued and outstanding as of December 31, 2017 and December 31, 2016, respectively		7			6
4,298,433 and 3,709,862 shares issued and outstanding as of December 31, 2017 and December 31, 2016, respectively - Related party		4			4
Class A common stock, $0.001 par value, 200,000,000 shares authorized and 16,075,244 and 15,861,704 shares issued and outstanding as of December 31, 2017 and December 31, 2016, respectively		16			16
Class B common stock, $0.001 par value, 50,000,000 shares authorized and 3,333,333 shares issued and outstanding as of December 31, 2017 and December 31, 2016		3			3
Additional paid-in capital		301,430			274,055
Accumulated deficit		(78,874	)		(63,739	)
Total stockholders’ equity		222,586			210,345
Non-controlling interest		27,799			26,849
Total equity		250,385			237,194
Total liabilities and equity	$	943,041		$	951,067

The accompanying notes are an integral part of these consolidated financial statements.

F-31

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(In thousands, except share and per share amounts)

	Year Ended December 31,
	2017			2016
Oil, natural gas, and NGL sales	$	51,653		$	195,058
Oil, natural gas, and NGL sales — Related party		366,798			649
Production handling and other income		14,846			7,540
Production handling and other income — Related party		1,114			72
Total revenues		434,411			203,319
Operating expenses:
Lease operating expenses		87,222			67,918
Lease operating expenses — Related party		10,338			—
Workover, repair, and maintenance expenses		17,441			12,754
Workover, repair, and maintenance expenses — Related party		1,201			—
Depreciation, depletion, and amortization		170,372			104,584
General and administrative expenses		42,397			35,078
Accretion of asset retirement obligations		31,392			21,669
Total operating expenses		360,363			242,003
Operating income (loss)		74,048			(38,684	)
Other income (expense):
Interest income		1,574			3,787
Interest income — Related party		2,596			6
Interest expense		(60,307	)		(31,545	)
Gain (loss) on derivatives, net		5,020			(9,153	)
Other income		200			123
Total other expense		(50,917	)		(36,782	)
Income (loss) before income taxes		23,131			(75,466	)
Income tax expense		14,095			—
Net income (loss)		9,036			(75,466	)
Net income (loss) attributable to non-controlling interest		2,581			(14,371	)
Net income (loss) attributable to EnVen Energy Corporation		6,455			(61,095	)
Series A preferred stock dividends		(13,466	)		(31	)
Series A preferred stock dividends — Related party		(8,124	)		(18	)
Net loss attributable to EnVen Energy Corporation common stockholders	$	(15,135	)	$	(61,144	)
Net loss per common share — basic and diluted	$	(0.95	)	$	(4.13	)
Weighted average common shares outstanding — basic and diluted		15,912,950			14,795,005

The accompanying notes are an integral part of these consolidated financial statements.

F-32

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Changes in Equity

(In thousands, except share information)

	Series A preferred stock				Class A common stock					Class B common stock
	Shares		Amount		Shares			Amount		Shares		Amount		Additional paid-in capital			Accumulated deficit			Total stockholders’ equity			Non- controlling interest			Total equity
Balance as of January 1, 2016		—	$	—		13,732,925		$	14		3,333,333	$	3	$	125,807		$	(2,595	)	$	123,229		$	47,851		$	171,080
Issuance of Series A preferred stock		6,159,596		6		—			—		—		—		72,729			—			72,735			—			72,735
Issuance of Series A preferred stock —related party		3,708,334		4		—			—		—		—		44,496			—			44,500			—			44,500
Issuance of Class A common stock						2,128,779			2		—		—		21,286			—			21,288			—			21,288
Change in ownership due to stock issuances		—		—		—			—		—		—		6,631			—			6,631			(6,631	)		—
Stock-based compensation						—			—		—		—		3,057			—			3,057			—			3,057
Series A preferred stock dividends		2,538		—		—			—		—		—		31			(31	)		—			—			—
Series A preferred stock dividends — related party		1,528		—		—			—		—		—		18			(18	)		—			—			—
Net loss		—		—		—			—		—		—		—			(61,095	)		(61,095	)		(14,371	)		(75,466	)
Balance as of December 31, 2016		9,871,996	$	10		15,861,704		$	16		3,333,333	$	3	$	274,055		$	(63,739	)	$	210,345		$	26,849		$	237,194
Issuance of Class A common stock related to stock-based compensation		—		—		331,947			—						—			—			—						—
Tax payments related to stock-based compensation		—		—		(118,407	)		—		—		—		(1,911	)		—			(1,911	)		—			(1,911	)
Change in ownership due to stock issuance		—		—		—			—		—		—		1,631			—			1,631			(1,631	)		—
Stock-based compensation		—		—		—			—		—		—		6,066			—			6,066			—			6,066
Series A preferred stock dividends		977,625		1		—			—		—		—		11,731			(11,732	)		—			—			—
Series A preferred stock dividends — related party		588,571		—		—			—		—		—		7,062			(7,062	)		—			—			—
Series A preferred stock dividends — beneficial conversion feature		—		—		—			—		—		—		1,734			(1,734	)		—						—
Series A preferred stock dividends — beneficial conversion feature — Related party		—		—		—			—		—		—		1,062			(1,062	)		—						—
Net income		—		—		—			—		—		—		—			6,455			6,455			2,581			9,036
Balance as of December 31, 2017		11,438,192	$	11		16,075,244		$	16		3,333,333	$	3	$	301,430		$	(78,874	)	$	222,586		$	27,799		$	250,385

The accompanying notes are an integral part of these consolidated financial statements.

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ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In thousands)

	Year Ended December 31,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	9,036		$	(75,466	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		170,372			104,584
Write-offs of uncollectible accounts receivable		2,242			1,673
Loss on disposition of property and equipment		(21	)		—
Derivative instruments:
(Gain) loss on derivatives, net		(5,020	)		9,153
Cash received for derivative settlements, net		18,047			1,601
Amortization of deferred financing costs and debt discount		9,967			2,439
Accretion of asset retirement obligations		31,392			21,669
Non-cash interest income		(1,574	)		(3,787	)
Non-cash interest income - Related party		(2,596	)		(6	)
Non-cash interest expense		529			331
Stock-based compensation		6,066			3,057
Excess tax benefit from stock-based compensation		521			—
Changes in operating assets and liabilities:
Accounts receivable		(13,512	)		(6,231	)
Accounts receivable - Related party		(24,272	)		(15,287	)
Prepaid expenses		(9,981	)		(2,900	)
Prepaid expenses - Related party		—			3,436
Accounts payable		17,916			(8,387	)
Accounts payable - Related party		621			—
Accrued liabilities		690			4,791
Revenue and royalties payable		2,378			5,333
Revenue and royalties payable - Related party		7,200			—
Joint owner advances payable		62			(1,025	)
Natural gas imbalances		(377	)		434
Asset retirement obligations		(41,778	)		(18,458	)
Income tax payable		13,574			—
Net cash provided by operating activities		191,482			26,954
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net of cash acquired		—			(328	)
Acquisitions of oil and natural gas properties, net of cash  acquired - Related party		—			(208,540	)
Acquisition purchase price adjustment		507			—
Acquisition purchase price adjustment - Related party		14,001			—
Purchases of property and equipment		(97,331	)		(32,720	)
Change in other		(1,936	)		(2,043	)
Net cash used in investing activities		(84,759	)		(243,631	)
Cash flows from financing activities:
Proceeds from issuance of notes payable		9,700			6,037
Payments on notes payable		(14,195	)		(7,827	)
Proceeds from issuance of long-term debt		40,000			194,500
Payments on long-term debt		(133,000	)		(32,499	)
Proceeds from issuance of preferred stock		—			72,735
Proceeds from issuance of common stock		—			21,288
Payments of deferred financing costs		—			(11,601	)
Tax payments related to stock-based compensation		(1,911	)		—
Net cash (used in) provided by financing activities		(99,406	)		242,633
Net increase in cash, cash equivalents, restricted cash, and restricted cash equivalents		7,317			25,956
Cash, cash equivalents, restricted cash, and restricted cash equivalents - beginning of period		98,103			72,147
Cash, cash equivalents, restricted cash, and restricted cash equivalents - end of period	$	105,420		$	98,103

The accompanying notes are an integral part of these consolidated financial statements.

Refer to Note 18 - Supplemental Cash Flow Information for supplemental cash flow disclosures.

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ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Note 1 - Organization and Summary of Significant Accounting Policies

EnVen Energy Corporation (together with its subsidiaries, the “Company”) is an independent oil and natural gas company with headquarters in Houston, Texas, engaged in the development, exploitation, and acquisition of primarily oil in the deepwater region in the United States (“U.S.”) Gulf of Mexico. The Company’s focus is on operated, oil-weighted producing assets that provide strong free cash flow, lower risk, and attractive development and exploration opportunities.

Organization

On October 30, 2015, Energy Ventures GoM Holdings, LLC entered into an agreement to sell 13,732,925 units in a private offering, at a price of $10.00 per unit, to selected institutional investors (the “2015 Equity Offering”). Each unit consisted of one share of Class A common stock of Energy Ventures GoM Holdings, LLC $0.001 par value per share (“Class A Common Stock”), one warrant to purchase 0.07282 shares of Class A Common Stock at an exercise price of $12.50 per share (“Series A Warrant”), and one warrant to purchase 0.07282 shares of Class A Common Stock at an exercise price of $15.00 per share (“Series B Warrant”). The 2015 Equity Offering resulted in net proceeds of approximately $125.7 million, including underwriter discounts and offering expenses of $7.6 million. The net proceeds were used to fund the Company’s capital program, including acquisitions.

Prior to the closing of the 2015 Equity Offering, Energy Ventures GoM Holdings, LLC was converted from a limited liability company to a Delaware corporation and renamed EnVen Energy Corporation (the “Company”).

Refer to Note 12 - Stockholders’ Equity for further discussion of the 2015 Equity Offering.

Basis of Presentation and Consolidation

The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) and include the accounts for the Company and entities in which it has control. All significant intercompany balances and transactions have been eliminated.

The Company has reclassified certain amounts in the prior year financial statements to conform to the current period presentation. As a result of the Company’s adoption of Accounting Standards Update (“ASU”) No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”) effective December 31, 2017, the Company retrospectively adjusted certain balances in the accompanying audited consolidated statements of cash flows for the years ended December 31, 2016. Refer to Recently Issued Accounting Standards - Adopted below for the reclassification effects of ASU 2016-18 for the year ended December 31, 2016. These reclassifications did not have a material impact on previously reported cash flows.

The Company owns the majority interest (approximately 89.2% as of December 31, 2017) of and controls its subsidiary, Energy Ventures GoM LLC (“GoM”); therefore, it is reflected as a consolidated subsidiary in the accompanying audited consolidated financial statements. The remaining ownership interest (approximately 10.8% as of December 31, 2017) not held by the Company (the “Non-controlling Interest”) is included the accompanying audited consolidated financial statements as non-controlling interest. GoM is considered a variable interest entity (“VIE”) for which the Company is the primary beneficiary, as it is the sole managing member of GoM and has the power to direct the activities most significant to GoM’s economic performance, as well as the obligation to absorb losses and receive benefits that are potentially significant. Refer to Note 12 - Stockholders’ Equity for a further discussion of the Company’s ownership interest in GoM.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and

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liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management believes its estimates and assumptions to be reasonable under the circumstances. Certain estimates and assumptions are inherently unpredictable and actual results could differ from those estimates.

Significant estimates include volumes of proved oil and natural gas reserves, which are the basis for calculating DD&A of proved oil and natural gas properties, the present value of estimated future net revenues included in the full cost ceiling test used to calculate any impairments of oil and natural gas properties, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated costs and timing of cash outflows underlying asset retirement obligations (“ARO”). Oil and natural gas reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties and assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, oil and natural gas prices, timing and amounts of development costs, and operating expenses, all of which could vary from the Company’s estimates. Other significant items subject to management’s estimates and assumptions include, but are not limited to, (i) the valuation of acquired assets and liabilities assumed (ii) the fair value of derivative instruments, (iii) the useful lives of fixed assets, (iii) deferred income taxes and deferred income tax valuation allowances, (iv) the valuation of the Company’s restricted stock awards and units (“Restricted Stock”), stock options, and related stock-based compensation expenses, and (v) other contingencies.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an initial maturity of three months or less to be cash and cash equivalents.

Restricted Cash and Restricted Cash Equivalents

Restricted cash and restricted cash equivalents include amounts held in escrow for future P&A obligations. In connection with the certain acquisitions, the Company is required to deposit funds in escrow accounts to use for future P&A obligation costs assumed in the acquisitions. In addition, the Bureau of Ocean Management (“BOEM”) and certain third parties require the Company to post supplemental and performance bonds as a means to ensure its decommissioning obligations. The Company enters into arrangements with surety companies who provide such bonds on its behalf and it may be required to provide cash collateral to support the issuance of these bonds. Refer to Note 14 - Commitments and Contingencies for a discussion of these requirements.

Accounts Receivable

Oil, natural gas, and NGL sales receivable consist of uncollateralized accrued oil, natural gas, and NGL revenue due under normal trade terms, generally requiring payment within 60 days of production. Joint interest and other receivables consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date and, at times, receivables from the counterparties to the Company’s derivative contracts. In the Company’s capacity as operator, it incurs drilling, operating, and P&A costs that are billed to the Company’s partners based on their respective working interests. For receivables from joint interest owners, the Company typically has the ability to withhold revenue distributions to recover any unpaid joint operations billings that are past due.

Accounts receivable are stated at the amount the Company expects to collect. The Company regularly reviews collectability and establishes provisions for losses if it is determined that collection of all or a part of an outstanding balance is not probable. The Company wrote off $2.2 million and $1.7 million of receivable balances during the years ended December 31, 2017 and 2016, respectively. These uncollectible receivables are written off to LOE or G&A, depending on the nature of the receivable, in the accompanying audited consolidated statements of operations. The Company had no allowance for doubtful accounts as of December 31, 2017 and 2016.

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Oil and Natural Gas Properties

The Company follows the full cost method of accounting for oil and natural gas activities and capitalizes all costs associated with the acquisition, exploration, and development of oil and natural gas properties. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals, costs of drilling, completing and equipping successful and unsuccessful oil and natural gas wells, and directly related costs. When the Company sells or convey interest in oil and natural gas properties, it reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company does not recognize a gain or loss on the sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves.

Proved oil and natural gas reserves are currently defined by the Securities and Exchange Commission (“SEC”) as the volumes of reservoirs that appear with reasonable certainty to be recoverable in the future from known based on geological and engineering data under existing economic and operating conditions and are estimated annually by an independent petroleum engineering firm.

Certain oil and natural gas property costs represent investments in unproved properties and are excluded from costs being depleted. These costs include nonproducing leasehold and geological and geophysical costs associated with unproved acreage and exploration drilling costs. Unproved properties and exploratory costs are excluded from the depreciable base until management determines the existence of proved reserves on the respective property or the costs are impaired. The Company reviews unproved properties to determine if the costs should be reclassified and included as a part of the depreciable base at least quarterly.

The capitalized costs of proved oil and natural gas properties, net of accumulated DD&A plus estimated future development costs related to proved oil and natural gas reserves and estimated future P&A costs are amortized on a unit of production method over the estimated productive life of the proved reserves to determine DD&A for each period. DD&A related to oil and natural gas properties for the years ended December 31, 2017 and 2016 was $169.7 million and $103.7 million, respectively.

Under the full cost method of accounting, the Company performs the full cost ceiling test at the end of each reporting period. Per the full cost ceiling test, net capitalized costs less deferred income taxes are limited to the present value of estimated future net cash flows from proved oil and natural gas reserves plus the cost of unproved properties not being amortized and less deferred income taxes (the ceiling limitation). If the net capitalized costs exceed the ceiling limitation, the Company recognizes an impairment equal to the excess of the net capitalized costs over the ceiling limitation. The Company did not recognize impairment for the years ended December 31, 2017 and 2016.

Other Property and Equipment

Other property and equipment consists of computer hardware and software, leasehold improvements, furniture, and fixtures, which is depreciated using the straight line method over their estimated useful lives ranging from 2 to 7 years.

Asset Retirement Obligations

The Company’s oil and natural gas properties include estimates of future expenditures to P&A wells and remove platforms, pipelines, and facilities after the reserves have been depleted. The present values of these ARO are recognized as a liability and as an increase in capitalized oil and natural gas properties. Capitalized ARO is depleted over the productive lives of the oil and natural gas properties while the ARO liabilities are accreted to their expected settlement values over the productive lives of the oil and natural gas properties.

ARO requires estimates of the future costs of removal and restoration, productive lives of the oil and natural gas properties based on reserve estimates, and future inflation rates. Estimated costs consider historical experience,

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third-party estimates, and state regulatory requirements but do not consider salvage values. These costs could be subject to revisions in subsequent years due to changes in regulatory requirements, the estimated P&A cost, and the estimated timing of oil and natural gas property retirement. The Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement, in which case the gain or loss is included in capitalized oil and natural gas properties. Refer to Note 10 - Asset Retirement Obligations for a further discussion of the Company’s ARO.

Notes Receivable

Notes receivable consists of commitments from sellers of oil and natural gas properties, acquired by the Company, related to the costs associated with the Company’s performance of the assumed P&A obligations. These commitments are recorded at present value using effective interest rates of 8.0% and 12.0%. The related discounts are amortized to Interest income on the accompanying audited consolidated statements of operations based on the expected timing of the completion of the P&A obligations. Refer to Note 8 - Note Receivable for a further discussion of the Company’s notes receivable.

Derivative Instruments

The Company utilizes commodity derivative instruments to reduce its exposure to oil and natural gas price volatility for a significant portion of its estimated proved developed producing oil and natural gas volumes. The fair values of the Company’s derivative instruments are measured on a recurring basis using a third-party industry-standard pricing model that is considered a Level 2 input within the fair value hierarchy. Refer to Note 5 - Fair Value Measurements for a further discussion of the fair value of the Company’s derivative instruments.

The Company has not designated any of its derivative instruments as hedges for accounting purposes; therefore, any gains or losses resulting from changes in the fair values of the Company’s outstanding derivatives during the period are recognized in Gain (loss) on derivatives, net in the accompanying audited consolidated statements of operations. The Company has elected to net its derivate instrument fair values executed with the same counterparty, pursuant to the ISDA master agreements, which provide for the net settlement over the term of the contract and in the event of the default or termination of the contract. Refer to Note 4 Derivative Instruments for a further discussion of the Company’s outstanding derivative instruments.

Debt Issuance Costs

Debt issuance costs related to the Company’s first lien senior secured revolving credit facility (“Revolving Credit Facility”) and second lien term loan facility (the “Second Lien Term Loan”) are capitalized as deferred financing costs and amortized over the term of the related agreements. The unamortized portion of the deferred financing costs associated with the Company’s Revolving Credit Facility is included in Other assets on the accompanying audited consolidated balance sheets. The unamortized portion of the deferred financing costs associated with the Company’s Second Lien Term Loan is netted against the outstanding balance of the Second Lien Term Loan which is recorded as the Long-term debt, net of current portion on the accompanying audited consolidated balance sheets.

Series A Preferred Stock

The Company’s Series A convertible perpetual preferred stock (“Series A Preferred Stock”) is classified in the stockholders’ equity section of the accompanying audited consolidated balance sheets as the shares are not mandatorily redeemable nor do they contain an unconditional conversion obligation.

The holders of Series A Preferred Stock are entitled to receive dividends, at the election of the Company’s board of directors (the “Board”), in cash or in shares of Series A Preferred Stock (“PIK Shares”). Historically, the Board has elected to declare PIK Share dividends on a quarterly basis. Since the Board has the option to pay the

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dividends in cash or in PIK Shares, the PIK Share dividends are deemed discretionary and are recorded at the declaration date at their stated rate (rather than at fair value) as a reduction to Net income (loss) to determine Net loss attributable to EnVen Energy Corporation common stockholders on the accompanying audited consolidated statements of operations.

At the end of each reporting period and each time PIK Share dividends are declared, the Company must evaluate if there is a beneficial conversion feature related to the PIK Share dividends by comparing the fair value of the Company’s Class A Common Stock to the issuance price of the Series A Preferred Stock of $12.00 per share. As of December 31, 2017, the Company recognized a beneficial conversion feature of $2.8 million related to the PIK Share dividends, which is included in the Series A preferred stock dividends line item on the accompanying audited consolidated statements of operations.

For a discussion of the Company’s Series A Preferred Stock and the associated PIK Share dividends and beneficial conversion feature, refer to Note 12 - Stockholders’ Equity.

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Refer to Note 14 - Commitments and Contingencies for a further discussion of the Company’s commitments as of December 31, 2017.

Revenue Recognition

The Company recognizes its oil revenues using the sales method. Under this method, oil revenues are based on the quantities of production sold to purchasers at the time the product is delivered and the title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred.

The Company recognizes its natural gas sales using the entitlements method, which could result in natural gas balances. Natural gas imbalances occur when the Company sells more or less natural gas production than its entitled ownership percentage of the total natural gas production. The Company records a natural gas imbalance liability for any revenue amount received in excess of its ownership share and a natural gas imbalance asset for any revenue amounts received less than its ownership share of the production that should have been provided. The Company had a natural gas imbalance net liability recorded on the accompanying audited consolidated balance sheets of $0.7 million and $1.1 million as of December 31, 2017 and 2016, respectively.

General and Administrative Expenses

G&A expenses consist of overhead, including salaries, incentive compensation, benefits for the Company’s corporate staff, costs of maintaining its headquarters, and costs of managing its production and development operations. G&A expenses also include software fees and audit, legal compliance, and other professional service fees.

Under the full cost method of accounting, the Company capitalizes a portion of its salaries, wages, and benefits to the extent that they are directly allocable to capital exploration and development activity. In addition, the Company records certain of these costs as LOE when they are directly attributable to maintaining the oil, natural gas, and NGL production of its operated oil and natural gas properties. For oil and natural gas properties for which the Company is the operator, it receives a reimbursement for a portion of these costs and allowable overhead from other working interest owners during the drilling and production phases of the property.

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Stock-based Compensation

The Company recognizes stock-based compensation expense related to its Restricted Stock and stock options based on the fair value of the Restricted Stock and stock options on the date of grant. The Company’s Restricted Stock does not have any post-vesting restrictions; therefore, the fair value of each share of Restricted Stock on the date of grant is determined based on the per share fair value of the Company’s Class A Common Stock on a minority, non-marketable basis. The estimates of fair value of the Company’s Class A Common Stock are highly complex and subjective, incorporating significant judgments and estimates in the fair value assumptions. Refer to Note 5 - Fair Value Measurements for a discussion of the fair value of the Company’s Class A Common Stock. The fair value of the stock options granted is estimated at the date of grant using the Black-Scholes option pricing model.

Compensation expense related to Restricted Stock and stock options with time-based vestings is recognized using the straight-line method over the period during which the employee or board member is required to provide services in exchange for the award. Compensation expense related to Restricted Stock with performance-based vestings is only recognized when the performance condition is deemed probable of occurring. The Company has elected to not estimate the forfeiture rate of its Restricted Stock or stock options in its initial calculation of compensation expense, but instead will adjust compensation expense for forfeitures as they occur. Refer to Note 13 - Employee Benefit Plans for further information related to the Company’s Restricted Stock and stock options.

Income Taxes

The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize deferred income tax assets, including net operating losses. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. As of December 31, 2017, the Company believes it is more likely than not that it will not realize the benefit of its deferred tax asset and accordingly has not removed the valuation allowance. Assuming the continuation of the Company’s valuation allowance, it anticipates cash tax payments to approximately equal income tax expense for the next three years.

The Company’s effective tax rate for the year ended December 31, 2017 was 60.9%. Refer to Note 16 - Income Taxes for a full reconciliation of the Company’s effective tax rate to the U.S. federal statutory rate.

Recently Issued Accounting Standards - Adopted

In March 2016, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2016–09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-based Payment Accounting (“ASU 2016-09”), which simplifies the accounting for stock-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholdings, classification of awards as either equity or liabilities, and classification on the statements of cash flows. The Company adopted this ASU on January 1, 2017. As a result of adoption, stock-based compensation excess tax benefits and tax deficiencies resulting from the exercise of stock-based compensation awards are reflected in the consolidated statements of operations as a component of the provision for income taxes and in the consolidated statements of cash flows as an operating activity. Additionally, shares withheld by the Company on behalf of Restricted Stock holders to satisfy tax

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withholding requirements are reflected as a component of financing activities on the consolidated statements of cash flows. The Company will continue to account for forfeitures of Restricted Stock and stock options as they occur when determining its stock-based compensation expense. The adoption of this ASU did not have a material impact on the Company’s consolidated financial statements.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. The Company has evaluated ASU 2016-15 and concluded there is no impact on its consolidated statements of cash flows.

In November 2016, the FASB issued ASU No. 2016-18, which requires the amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning of the period and end of period totals in that statement of cash flows. The Company has evaluated the provisions of ASU 2016-18 and has elected to early adopt this ASU effective on December 31, 2017, using the retrospective approach. As a result, the accompanying audited consolidated statements of cash flows for the years ended December 31, 2016 have been adjusted to reflect the effects of adopting this ASU.

The following table presents the effects of ASU 2016-18 for the year ended December 31, 2016:

	Year Ended December 31, 2016
	Prior to Adoption			After Adoption
	(In thousands)
Changes in restricted cash	$	(2,865	)	$	—
Net cash used in investing activities		(246,496	)		(243,631	)
Net increase in cash, cash equivalents, restricted cash, and restricted cash equivalents	$	23,091		$	25,956

Refer to Note 18 - Supplemental Cash Flow Information for a reconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents reported on the accompanying audited consolidated balance sheets to the total amounts reported on the accompanying audited consolidated statements of cash flows.

Recently Issued Accounting Standards - Not Yet Adopted

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), which provides a more robust framework to use in determining when a set of assets and activities constitute a business. ASU 2017-01 provides a screen to determine when a set of assets does not constitute a business and if the screen is not met, it (i) requires that a set of assets must include an input and a substantive process that, together, significantly contribute to the ability to create output and (ii) removes the evaluation of whether a market participant could replace the missing elements. For non-public entities, ASU 2017-01 is effective for fiscal years beginning after December 15, 2018 using a prospective approach. The Company is currently evaluating the impact the adoption of this ASU may have on its consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”) as a new ASC Topic, (“ASC 606”) which supersedes revenue recognition requirements in ASC Topic 605, Revenue Recognition. This standard requires an entity to recognize the amount of revenue to which it expects to be entitled to for the transfer of goods or services promised to customers. Additionally, the standard requires entities to disclose the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross-versus-net basis and the use of the entitlements method to account for natural gas

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imbalances. For non-public entities, the standard and the related interpretive guidance is effective for interim and annual periods beginning after December 15, 2018.

The Company has evaluated all of its existing revenue streams by reviewing the associated contracts and accounting policies and identified any arrangements for which an accounting difference may arise due to the conversion to the new standard. Additionally, the Company evaluated its additional disclosure requirements and identified the practical expedients it can elect relating to the standard. The Company determined that the implementation of this standard will not have a material impact on the timing of its revenue recognition, financial position, results of operations, net income, or cash flows but will impact its revenue-related disclosures and future presentation of revenues and expenses and it will early adopt this standard effective January 1, 2018 using the modified retrospective method. As a result of the implementation, the cumulative effect adjustment recognized in the opening balance of the accumulated deficit will be immaterial. The Company will apply this change in accounting policy prospectively therefore, revenues reported in periods prior to January 1, 2018 will not change.

Additionally, the standard will impact the Company’s future presentation of revenues and expenses. Currently, the Company presents its oil, natural gas, and NGL sales revenues net of transportation, gathering, and processing costs. With the adoption of the standard, beginning January 1, 2018, the Company will present its oil, natural gas, and NGL sales revenues gross of the associated transportation, gathering, and processing costs for certain of its operated properties. This change from net to gross presentation will result in an increase in the Company’s oil, natural gas, and NGL sales revenues and a corresponding increase in LOE, resulting in no net impact on the results of operations, net income, or cash flows.

The Company cannot estimate the future impact of the changes resulting from the adoption of this standard on its future revenues and expenses due to uncertainties with respect to future sales volumes, service costs, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period.

In February 2016, the FASB issued ASU No. 2016–02, Leases (Topic 842) (“ASU 2016-02”), which will require lessees to recognize a right-of-use asset and a lease liability on their balance sheet for all leases, including operating leases, with a term of greater than 12 months. ASU 2016–02 will also require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. For non-public entities, ASU 2016-02 is effective for fiscal years beginning after December 15, 2019 and interim periods within fiscal years beginning after December 15, 2020. The Company continues to evaluate the impact the adoption of this ASU may have on its consolidated financial statements and has engaged a third-party specialist to assist in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Standard setting guidance and interpretations continue to evolve and are being monitored for applicability and impact to the Company’s business and industry. Based on an initial review of the new ASU and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time.

Note 2 - Significant Acquisitions of Oil and Natural Gas Properties

Shell Acquisition

On December 30, 2016, the Company acquired 100% working interests in the U.S. Gulf of Mexico Green Canyon 158/202 (“Brutus”) and 248 (“Glider”) fields, including the Brutus tension-leg platform, a subsea facility, 16 wells, and 2 transportation pipelines from Shell (the “Shell Acquisition”). The total adjusted consideration of $238.7 million included an initial purchase price of $375.0 million and total purchase price adjustments from the contractual effective date of the acquisition, January 1, 2016, through the acquisition date of $136.3 million, including a $14.0 million final adjustment in the fourth quarter of 2017.

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As the Shell Acquisition was a business combination accounted for by applying the acquisition method of accounting, the assets acquired and liabilities assumed were recognized at their respective fair values at the acquisition date. The Company had one year from the acquisition date to finalize these values and record adjustments to the initial purchase price to reflect information obtained about facts and circumstances that existed as of the acquisition date. The Company finalized its assessment during the three months ended December 31, 2017.

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date:

	(In thousands)
Oil and natural gas properties	$	305,574
Asset retirement obligations		(66,897	)
Total consideration paid	$	238,677

A portion of the consideration for the Shell Acquisition was funded with the cash proceeds from the issuance of Series A Preferred Stock (refer to Note 12 - Stockholders’ Equity), additional borrowings on the Revolving Credit Facility, and the exercise of an accordion feature of the Company’s Second Lien Term Loan (refer to Note 11 - Long-term Debt). Additionally, $44.5 million of the consideration was provided by issuing 3,708,334 shares of Series A Preferred Stock to Shell, with an issuance price of $12.00 per share on the date of acquisition (the “Shell Series A Preferred Stock Offering”). Refer to Note 20 - Subsequent Events for a discussion of the repurchase of the Series A Preferred Stock from Shell.

The results of the Brutus and Glider properties acquired from Shell have been included in the accompanying audited consolidated statement of operations for the year ended December 31, 2016 subsequent to the December 30, 2016 acquisition date. The Brutus and Glider properties contributed $0.7 million and $0.6 million to the Company’s revenues and earnings, respectively, during the year ended December 31, 2016.

Pro Forma Results of Operations

The following unaudited pro forma consolidated financial information has been prepared to reflect the Shell Acquisition as if the acquisition had occurred on January 1, 2016. The unaudited pro forma financial information is based on the historical consolidated statements of operations of the Company and the Brutus and Glider fields for the year ended December 31, 2016.

	(In thousands, except per share amounts)
Total revenues	$	411,676
Net loss		(15,399	)
Net loss attributable to non-controlling interest		(1,749	)
Net loss attributable to EnVen Energy Corporation common stockholders		(32,436	)
Net loss per common share – basic and diluted	$	(2.19	)

The above supplemental unaudited pro forma consolidated financial information has been prepared for illustrative purposes only and is not intended to be indicative of the results of operations that actually would have occurred had the acquisition occurred on January 1, 2016, nor is such information indicative of any expected results of operations in future periods. The pro forma adjustments to the consolidated statements of operations for the year ended December 31, 2016 included recognizing the incremental $208.4 million of revenues and $62.5 million of lease operating expenses from the acquired Brutus and Glider fields, increasing DD&A expense by $78.0 million for the acquired assets to correspond with the Company’s full cost method of accounting, increasing accretion of asset retirement obligations expense by $7.8 million for the accretion associated with the decomissioning obligations assumed in the transaction, increasing the Series A preferred stock dividends by $18.7 million and adjusting the net income attributable to EnVen Energy Corporation to reflect additional preferred dividend issuances.

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Marathon Acquisitions

First closing. On December 18, 2015, the Company acquired ownership interests in and operatorship of the U.S. Gulf of Mexico Ewing Bank 873/917/963, including the Lobster platform (collectively, “Lobster”), a subsea facility, and 29 wells, and ownership interest in the Vioska Knoll 742/786/830 (“Petronius”) field, including 23 wells, from Marathon Oil Company (“Marathon”) (the “First Closing”). The total consideration of $104.6 million included an initial purchase price of $177.2 million and purchase price adjustments from the contractual effective date of the purchase, January 1, 2015, through the acquisition date of $72.6 million.

Second closing. On February 5, 2016, the Company acquired ownership interests in the U.S. Gulf of Mexico Atwater Valley 574/575/618 (“Neptune”) field, including the Neptune platform, a subsea facility and 7 wells, and an overriding royalty interest in the Ship Shoal 243 lease from Marathon (the acquisitions on December 18, 2015 and February 5, 2016 collectively, the “Marathon Acquisitions”). The total consideration of $4.0 million included an initial purchase price of $27.5 million, of which a $1.3 million earnest money deposit was funded during the year ended December 31, 2015, and purchase price adjustments from the contractual effective date of the purchase, January 1, 2015, through the acquisition date of $23.5 million.

As the Marathon Acquisitions were business combinations accounted for by applying the acquisition method of accounting, the assets acquired and liabilities assumed were recognized at their respective fair values at the acquisition date. The Company finalized the acquisition accounting during 2016 and there were no material changes to the fair value of the assets acquired and liabilities assumed.

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed in the First Closing as of the acquisition date of December 18, 2015:

	(In thousands)
Oil and natural gas properties	$	136,205
Asset retirement obligations		(31,589	)
Total consideration paid	$	104,616

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed in the Second Closing as of the acquisition date of February 5, 2016:

	(In thousands)
Oil and natural gas properties	$	30,279
Asset retirement obligations		(26,233	)
Total consideration paid	$	4,046

The Marathon Acquisitions were funded with the net cash proceeds of the 2015 Equity Offering, refer to Note 1 -Organization and Summary of Significant Accounting Policies - Organization.

Note 3 Loss per Share

Basic net loss per common share is calculated by dividing the Net loss attributable to EnVen Energy Corporation common stockholders by the weighted average common shares outstanding for the period. In a period with a Net loss, all potentially dilutive common shares outstanding are considered anti-dilutive and therefore excluded from the calculation of diluted weighted average common shares outstanding, resulting in the calculation of diluted loss per common share to equal basic loss per common share.

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The Company’s basic and diluted loss per common share calculations are as follows for the periods indicated:

	Year Ended December 31,
	2017			2016
	(In thousands, except share and per share amounts)
Net loss attributable to EnVen Energy Corporation common stockholders (numerator)	$	(15,135	)	$	(61,144	)
Weighted average common shares outstanding (denominator)		15,912,950			14,795,005
Net loss per common share - basic and diluted	$	(0.95	)	$	(4.13	)
Weighted average anti-dilutive shares excluded from common shares outstanding(1)		10,071,463			173,694

⁽¹⁾  The increase in weighted average anti-dilutive shares excluded from common shares outstanding during the year ended December 31, 2017 compared to during the year ended December 31, 2016 primarily relates to the Series A Preferred Stock issued on December 30, 2016 and the related PIK share dividends issued throughout December 31, 2017.

The Company’s Restricted Stock is considered to be a participating security, therefore, in periods with net income, undistributed earnings are allocated among the Company’s common shares and issued non-vested Restricted Stock shares per the two-class method. The Company’s participating securities do not participate in undistributed net losses because they are not obligated to do so.

In periods where the Company has net income, diluted earnings per share is calculated by dividing Net income allocated to common shares by the weighted average common shares outstanding during the period, including potentially dilutive common shares outstanding during the period determined by the treasury stock method. Potentially dilutive common shares are determined by including the following, as applicable in the periods presented: (i) the vesting of Restricted Stock, (ii) the exercise of stock options at an average price greater than their exercise price, (iii) the exercise of warrants at an average price greater than their exercise price, and (iv) the conversion of preferred shares.

Note 4 - Derivative Instruments

The Company utilizes commodity derivative instruments to reduce its exposure to oil and natural gas price volatility for a significant portion of its estimated proved developed producing oil and natural gas volumes. The Company has entered into various derivative contracts with major financial institutions, which, as of December 31, 2017, settle monthly through September 2019.

The Company’s oil and natural gas derivative instruments consist of various instruments, including financially settled oil and natural gas call options, put options, and swaps, or combinations of these arrangements, which are described below.

• Swaps: The Company receives a fixed price and pays a variable market price to the counterparty for contracted commodity volumes over specified time periods.

• Sold Call Options: A sold call option gives the counterparty the right, but not the obligation, to purchase the underlying commodity volumes from the Company at a specified price (“strike/ceiling price”) over a specified time period. At settlement, if the market price is above the fixed ceiling price of the sold call option, the Company pays the counterparty the difference. If the market price settles below the fixed ceiling price of the sold call option, no payment is due from either party.

• Purchased Put Options: A purchased put option gives the Company the right, but not the obligation, to sell the underlying commodity volumes to the counterparty at a specified price (“strike/floor price”)

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over a specified time period. At settlement, if the market price is below the fixed floor price of the purchased put option, the counterparty pays the Company the difference. If the market price settles above the fixed floor price of the purchased put option, no payment is due from either party.

• Put Spreads: A put spread is a combination of a sold put option and a purchased put option. At settlement, if the market price is below the sold put option strike price, the Company receives the difference between the two strike prices from the counterparty. If the market price settles below the purchased put option strike price but above the sold put option strike price, the Company receives the difference between the purchased put option strike price and the market price from the counterparty. If the market price settles above the purchased put option strike price, no payment is due from either party.

• Collars: A collar contains a purchased put option (“fixed floor price”) and a sold call option (“fixed ceiling price”). At settlement, if the market price is below the fixed floor price, the Company receives the difference between the fixed floor price and the market price from the counterparty. If the market price settles above the fixed ceiling price, the Company pays the counterparty the difference between the market price and the fixed ceiling price.

• Three-way Collars: A three-way collar combines a sold call option (“fixed ceiling price”), a purchased put option (“fixed floor price”), and a sold put option (“fixed subfloor price”). At settlement, if the market price is between the fixed floor price and the fixed subfloor price or is above the fixed ceiling price, the Company receives the fixed floor price from the counterparty or pays the counterparty the market price, respectively. If the market price settles below the fixed subfloor price, the Company receives the market price plus the difference between the fixed floor price and the fixed subfloor price from the counterparty. If the market price settles between the fixed floor price and fixed ceiling price, no payments are due from either party.

The Company’s oil and natural gas derivative contracts are indexed to WTI and HH, respectively, both of which are quoted on the NYMEX.

As of December 31, 2017, the Company’s outstanding oil and natural gas derivative instruments were as follows:

Oil
				Weighted Average Price ($/Bbl)
						Collars/Puts
Period	Instrument Type	Volumes (Bbls)		Swap Fixed Price		Subfloor		Floor		Ceiling
2018	Swaps		1,433,890	$	53.14	$	—	$	—	$	—
2018	Collars		1,925,636	$	—	$	—	$	45.00	$	62.91
2018	Three-way collars		857,013	$	—	$	40.00	$	50.00	$	65.08
2018	Purchased puts		958,047	$	—	$	—	$	49.53	$	—
2019	Swaps		763,563	$	50.70	$	—	$	—	$	—
2019	Purchased puts		135,000	$	—	$	—	$	45.00	$	—
2019	Put spreads		398,001	$	—	$	40.00	$	50.00	$	—

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Natural Gas
				Weighted Average Price ($/MMBtu)
						Collars/Puts
Period	Instrument Type	Volumes (MMBtus)		Swap Fixed Price		Subfloor		Floor		Ceiling
2018	Swaps		2,829,797	$	3.21	$	—	$	—	$	—
2018	Three-way collars		216,678	$	—	$	2.75	$	3.50	$	3.91
2018	Purchased puts		3,747,255	$	—	$	—	$	2.75	$	—
2019	Swaps		2,591,700	$	2.75	$	—	$	—	$	—
2019	Collars		680,139	$	—	$	—	$	3.00	$	3.50
2019	Purchased puts		906,861	$	—	$	—	$	2.75	$	—

The Company recognizes all of its derivative instruments at fair value as either an asset or as a liability on the accompanying audited consolidated balance sheets. The Company has not designated any of its derivative instruments as hedges for accounting purposes, therefore, any gains or losses resulting from changes in the fair values of the Company’s outstanding derivatives during the period are recognized in Gain (loss) on derivatives, net in the accompanying audited consolidated statements of operations. Additionally, any gains or losses from the settlement of derivative instruments during the period, any proceeds or payments related to early termination of derivative contracts, and any upfront premiums paid for new derivative contracts are recognized in Gain (loss) on derivatives, net in the accompanying audited consolidated statements of operations.

The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. The Company has elected to net its derivative instrument fair values executed with the same counterparty, pursuant to the ISDA master agreements, which provide for the net settlement over the term of the contract and in the event of the default or termination of the contract.

The Company monitors the creditworthiness of its derivative counterparties, all of which are lenders or affiliates of lenders participating in its Revolving Credit Facility, to determine if any credit risk adjustment is necessary to the fair values of its derivative instruments or if any nonperformance risk exists. The Company’s derivative counterparties are large financial institutions with investment-grade credit ratings, therefore, the Company believes it does not have any significant credit risk associated with its counterparties and does not currently anticipate any nonperformance from its counterparties.

In some cases, the Company might agree to pay a premium on certain of its purchased put option derivative contracts. The Company could agree to pay the premium upfront, in which case the premium payment is recorded as a derivative asset. The value of the premium is considered in the underlying derivative fair value and is adjusted in subsequent periods through Gain (loss) on derivatives, net in the accompanying audited consolidated statements of operations. Alternatively, the Company could defer the payment of the premium until the month the applicable derivative contract settles, in which case the Company recognizes the deferred premium obligation net against the derivative instruments fair value asset or liability, pursuant to the ISDA master netting agreements described above. In the period the derivative contract settles, the Company recognizes the deferred premium obligation in Gain (loss) on derivatives, net in the accompanying audited consolidated statements of operations.

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The following tables present the gross and net fair values of the Company’s derivative instruments, net of any applicable deferred premium obligations recorded on the accompanying audited consolidated balance sheets:

	December 31, 2017
	Gross Amounts Recognized			Gross Amounts Offset on the Consolidated Balance Sheets			Net Amounts Presented on the Consolidated Balance Sheets
	(In thousands)
Current assets	$	2,402		$	(2,402	)	$	—
Long-term assets		371			(371	)		—
Current liabilities		(15,201	)		2,402			(12,799	)
Long-term liabilities	$	(5,465	)	$	371		$	(5,094	)

	December 31, 2016
	Gross Amounts Recognized			Gross Amounts Offset on the Consolidated Balance Sheets			Net Amounts Presented on the Consolidated Balance Sheets
	(In thousands)
Current assets	$	4,990		$	(4,990	)	$	—
Long-term assets		6,766			(6,766	)		—
Current liabilities		(9,041	)		4,990			(4,051	)
Long-term liabilities	$	(7,581	)	$	6,766		$	(815	)

As of year ended December 31, 2017, the liability fair values of the Company’s derivative instruments are presented net of deferred premium obligations of $5.4 million. The Company did not have any deferred premium obligations as of the year ended December 31, 2016.

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The following table presents the components of Gain (loss) on derivatives, net on the accompanying audited consolidated statements of operations and amounts reflected in cash flows from operating activity in the statements of cash flows. Total cash received for derivative settlements, net reflects the gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price for those contracts. Any proceeds or payments related to early termination of derivative contracts and any upfront premiums paid for new derivative contracts during the period are included in the total cash received for derivative settlements, net. Additionally, deferred premium obligations paid reflect the cash premium payments associated with derivative contracts settled during the period. Total non-cash loss on derivatives, net represents the changes in the fair values of derivative instruments outstanding at the end of the period and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.

	Year Ended December 31,
	2017			2016
	(In thousands)
Cash received for derivative settlements, net:
Oil(1)	$	17,055		$	2,976
Natural gas		2,252			535
Deferred premium obligations paid		(1,260	)		(1,910	)
Total cash received for derivative settlements, net		18,047			1,601
Non-cash loss on derivatives:
Oil		(16,293	)		(7,678	)
Natural gas		3,266			(3,076	)
Total non-cash loss on derivatives, net		(13,027	)		(10,754	)
Gain (loss) on derivatives, net	$	5,020		$	(9,153	)

(1) During the year ended December 31, 2017, the Company terminated certain of its oil swap contracts before their contract settlement dates and repositioned its commodity derivative portfolio with oil purchased puts. As a result, cash received for oil derivative settlements, net includes the cash proceeds of $6.8 million from the early termination, net of upfront premiums of $1.7 million associated with the new purchased put contracts.

Note 5 - Fair Value Measurements

Certain of the Company’s assets and liabilities are carried at fair value and measured either on a recurring or non-recurring basis. The Company’s fair value measurements are based either on actual market data or assumptions that other market participants would use in pricing an asset or liability in an orderly transaction, using the valuation hierarchy prescribed by GAAP.

The GAAP valuation hierarchy categorizes assets and liabilities measured at fair value into one of three levels depending on the observability of inputs used to determine fair value. The three levels of the fair value hierarchy are as follows:

• Level 1: Unadjusted quoted prices for identical assets or liabilities in active markets.

• Level 2: Observable inputs other than Level 1 inputs. These include: quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets which are not active, or inputs that are corroborated by observable active market data.

• Level 3: Unobservable inputs for which little or no market data exists.

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The classification of an asset or liability within the fair value hierarchy is based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement of an asset or liability requires judgment and may affect the valuation of the fair value asset or liability and its placement within the fair value hierarchy. There have been no transfers between fair value hierarchy levels.

Assets and Liabilities Measured at Fair Value on Recurring Basis

Commodity derivative contracts. The fair values of the Company’s derivative instruments are measured on a recurring basis using a third-party industry-standard pricing model that considers various inputs such as quoted forward commodity prices, discount rates, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant data. These significant inputs are observable in the current market or can be corroborated by observable active market data and are therefore considered Level 2 inputs within the fair value hierarchy.

The following tables present the Company’s commodity derivative contract assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2017 and 2016 using the fair value hierarchy:

	Fair Value Measurement as of December 31, 2017
	Total			Level 1		Level 2			Level 3
	(In thousands)
Assets:
Commodity derivative contracts	$	2,773		$	—	$	2,773		$	—
Liabilities:
Commodity derivative contracts	$	(20,666	)	$	—	$	(20,666	)	$	—

	Fair Value Measurement as of December 31, 2016
	Total			Level 1		Level 2			Level 3
	(In thousands)
Assets:
Commodity derivative contracts	$	11,756		$	—	$	11,756		$	—
Liabilities:
Commodity derivative contracts	$	(16,622	)	$	—	$	(16,622	)	$	—

Assets and Liabilities Measured at Fair Value on Non-Recurring Basis

Acquisition-related assets and liabilities. The fair values of assets acquired and liabilities assumed are measured on a non-recurring basis on the acquisition date using a discounted cash flow model. The significant inputs used in the discounted cash flow model include estimates relating to oil and natural gas reserves, future commodity prices, timing of development, future operating costs, a credit-risk adjusted discount rate, and other relevant data. These significant inputs are based on unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. Refer to Note 2 - Significant Acquisitions of Oil and Natural Gas Properties for a discussion of the Company’s acquisitions.

Asset retirement obligations. The fair values of any additions to the Company’s ARO are measured on a non-recurring basis at the time a well is drilled or acquired using a discounted cash flow model. The significant inputs used in the discounted cash flow model include estimates relating to future P&A settlement timing and costs, a credit-risk adjusted discount rate, and inflation rates. These significant inputs are based on unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. Refer to Note 10 - Asset Retirement Obligations for the Company’s additions to ARO.

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Class A Common Stock. To the extent that there is not a recent arm’s-length market transaction, the per share fair value of the Company’s Class A Common Stock is estimated on a non-recurring basis at the grant date of the shares by a third party using an option pricing model (“OPM”). The OPM estimates the per share fair value of the Company’s Class A Common Stock on a minority, marketable basis, and applies a discount for lack of marketability to account for the illiquidity of the Company’s Class A Common Stock. The OPM allocates the Company’s total equity value to the various classes of equity in the Company’s capital structure, treating the Class A and Class B Common Stock and Series A Preferred Stock as options on the entity’s enterprise value and captures the option-like characteristics of common stock for entities whose common stock is a small portion of the total capital structure.

The significant inputs used in the OPM include the timing of an expected liquidity event date, equity volatility, risk-free rate, and an estimate of the Company’s total equity value as of the grant date of the shares. These significant inputs are based on and sensitive to unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. The estimates of fair value of the Company’s Class A Common Stock are highly complex and subjective, incorporating significant judgments and estimates in the fair value assumptions. Refer to Note 13 - Employee Benefit Plans for a discussion of the Company’s Restricted Stock and Stock Options.

Fair Value of Other Financial Instruments

Cash and cash equivalents, restricted cash and restricted cash equivalents, accounts receivable, and accounts payable. The carrying amounts of the Company’s cash and cash equivalents, restricted cash and restricted cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.

Notes receivable. The fair values of the Company’s notes receivable are measured on a non-recurring basis at the time the notes receivable are entered into using a discounted cash flow model. The significant inputs used in the discounted cash flow model are the effective interest rate and payment terms of the notes receivable. These significant inputs can be corroborated by observable active market data and are therefore considered Level 2 inputs within the fair value hierarchy. Refer to Note 8 - Notes Receivable for further information related to the Company’s notes receivable.

Notes payable. The fair values of the Company’s notes payable are measured on a non-recurring basis at the time the notes payable are entered into. The majority of the Company’s notes payable are measured using a discounted cash flow model. The significant inputs used in the discounted cash flow model are the effective interest rate and payment terms of the notes payable. These significant inputs can be corroborated by observable active market data and are therefore considered Level 2 inputs within the fair value hierarchy. The carrying value of one of the Company’s notes payable approximates fair value due to the short-term nature of the note payable. Refer to Note 9 - Notes Payable for further information related to the Company’s notes payable.

Long-term debt. The carrying amounts of the Company’s long-term debt related to variable interest rate borrowings under its Revolving Credit Facility and Second Lien Term Loan approximates fair value based on borrowing rates available to the Company for bank loans with similar terms and maturities, which are observable in the current market and are therefore considered Level 2 inputs within the fair value hierarchy. As of December 31, 2017, there were no indicators of change in the Company’s market spread.

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Note 6 - Prepaid Expenses

The Company’s prepaid expenses consisted of the following:

	December 31, 2017		December 31, 2016
	(In thousands)
Prepaid surety bond premiums and insurance	$	15,891	$	4,766
Prepaid well costs		4,366		5,699
Other prepaid expenses		1,327		1,139
Total prepaid expenses	$	21,584	$	11,604

Note 7 - Property and Equipment, net

The Company’s property and equipment, net consisted of the following:

	December 31, 2017			December 31, 2016
	(In thousands)
Proved oil and natural gas properties	$	1,045,891		$	944,675
Less: accumulated depreciation, depletion, and amortization		(368,938	)		(199,240	)
Proved oil and natural gas properties, net		676,953			745,435
Unproved oil and natural gas properties		12,648			6,328
Total oil and natural gas properties, net		689,601			751,763
Other property and equipment		4,212			3,832
Less: accumulated depreciation		(2,323	)		(1,670	)
Total other property and equipment, net		1,889			2,162
Total property and equipment, net	$	691,490		$	753,925

For the year ended December, 31, 2017, the Company’s proved oil and natural gas properties includes a drilling rig and related equipment purchased from Helmerich & Payne International Drilling Co. (“H&P”) for $18.0 million to be utilized in the development of assets acquired from Shell. Refer to Note 9 - Notes Payable for a further discussion related to the H&P drilling rig purchase.

For the years ended December 31, 2017 and 2016, the Company’s proved oil and natural gas properties include capitalized labor costs of $0.8 million and $0.8 million, respectively, related to labor costs directly allocable to capital exploration and development activity.

Note 8 - Notes Receivable

Notes receivable consist of commitments from sellers of oil and natural gas properties, acquired by the Company, related to the costs associated with the Company’s performance of the assumed long-term P&A obligations. Pursuant to agreements with the sellers, the Company is to receive an agreed upon amount at completion of the P&A obligations. The gross amounts of these obligations total $45.0 million and $21.2 million and are recorded at present value using effective interest rates of 8.0% and 12.0%, respectively. The related discounts are amortized into Interest income on the accompanying audited consolidated statements of operations based on the expected timing of the completion of the long-term P&A obligations. The Company recognized interest income related to these notes receivable of $4.2 million and $3.8 million for the years ended December 31, 2017 and 2016, respectively. The outstanding balances of these notes receivable were $34.1 million and $14.0 million, respectively, as of December 31, 2017 and $31.5 million and $12.4 million, respectively, as of December 31, 2016.

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Note 9 - Notes Payable

On February 24, 2017, the Company entered into an agreement to purchase a drilling rig and related equipment from H&P to be utilized in the development of assets acquired from Shell for a total purchase price of $18.0 million. The Company paid H&P cash consideration of $8.0 million, with the remaining $10.0 million to be paid in quarterly installments of $1.7 million, beginning July 1, 2017. The Company recorded the fair value of the installment payments as a note payable at an effective interest rate of 4.8% and is amortizing the discount into Interest expense on the accompanying audited consolidated statements of operations over the term of the installment period. During the year ended December 31, 2017, the Company paid quarterly installments of $3.3 million. As of December 31, 2017, the Company has a liability of $6.5 million recorded as a note payable for the remaining installment payments due to H&P.

The Company finances its commercial insurance program by entering into note payables with various terms. The first note payable was entered into on May 15, 2016 and required an initial installment of $1.5 million and nine monthly installments of principal and interest of $0.7 million, at an interest rate of 2.35%. For the years ended December 31, 2017 and 2016 the Company paid $1.3 million and $6.1 million, respectively, in principal and interest related to this note payable. As of December 31, 2016, the outstanding balance of this note payable was $1.3 million and the note was paid in full as of March 31, 2017. On May 15, 2017, a second note payable was entered into for financing commercial insurance, which required an initial installment of $1.9 million and nine monthly installments of principal and interest of $0.9 million, beginning on June 15, 2017, at an interest rate of 2.7%. For the year ended December 31, 2017, the Company paid $8.0 million of principal and interest. As of December 31, 2017, the outstanding balance of this note payable was $1.7 million.

On September 23, 2014, the Company entered into a master licensing agreement for the licensing of certain geophysical and geological information and materials, paying an initial installment of $6.0 million and three annual installments of $1.5 million. The Company recorded the fair value of the installment payments as a note payable at an effective interest rate of 3.3% and amortized the discount into interest expense over the term of the installment period. As of December 31, 2016, the outstanding balance of this note payable was $1.3 million and the note was paid in full as of December 31, 2017.

Note 10 - Asset Retirement Obligations

The Company’s primary ARO relates to future P&A costs on its oil and natural gas properties and related facility disposals. The Company records a liability at the fair value for ARO when it is incurred and the associated ARO cost is capitalized by increasing the carrying value of the related oil and natural gas properties. In subsequent periods, if the estimate of the ARO liability changes, the Company records an adjustment to both the ARO liability and the oil and natural gas properties. Over time, the liability accretes for the change in its present value, while the capitalized cost depletes over the useful life of the related asset. Upon settlement of the ARO, the Company either settles the obligation for its recorded liability amount or incurs a gain or loss, which is included in capitalized oil and natural gas properties.

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The following table presents the changes in the Company’s ARO:

	December 31, 2017			December 31, 2016
	(In thousands)
Asset retirement obligations at the beginning of the period	$	287,700		$	196,705
Liabilities assumed through acquisition		—			93,522
Liabilities settled		(47,326	)		(17,082	)
Revisions of previous estimates		4,318			(7,114	)
Accretion expense		31,392			21,669
Asset retirement obligations at the end of the period		276,084			287,700
Less: current portion of asset retirement obligations		(21,828	)		(44,228	)
Asset retirement obligations, less current portion	$	254,256		$	243,472

For the years ended December 31, 2017 and 2016, ARO liabilities settled includes a gain of $5.5 million and loss of $1.4 million, respectively, related to the settlement of certain P&A obligations below or above their original recorded amounts.

Revisions of previous estimates during the years ended December 31, 2017 and 2016 are attributable to changes in estimated cash flows and planned timing of P&A activities.

Refer to Note 5 - Fair Value Measurements for further discussion of the fair value of ARO.

Note 11 - Long-term Debt

The Company’s outstanding long-term debt balances as of the dates presented consist of the following:

	December 31, 2017			December 31, 2016
	(In thousands)
Revolving credit facility, weighted average interest rate of 5.09% and 5.11% as of December 31, 2017 and 2016, respectively	$	95,000		$	176,750
Second lien term loan, weighted average interest rate of 12.85% and 13.11% as of December 31, 2017 and 2016, respectively		202,500			213,750
Total long-term debt		297,500			390,500
Less: unamortized deferred financing costs and debt discount		(5,305	)		(10,736	)
Total long-term debt, net		292,195			379,764
Less: current portion of long-term debt		—			(11,250	)
Long-term debt, net of current portion	$	292,195		$	368,514

Revolving Credit Facility

In 2014, the Company entered into an agreement with a syndicate of banks and established the Revolving Credit Facility, which is secured by substantially all of the assets owned by the Company. As part of the 2018 Refinancing Transactions completed in February 2018, described in Note 20 - Subsequent Events - 2018 Refinancing Transactions, the maturity date of the Revolving Credit Facility was extended to January 26, 2022. Pursuant to the 2018 Refinancing Transactions, the Revolving Credit Facility has an initial borrowing base of $231.3 million (with lender commitments of $250.0 million) and a maximum line of credit to $500.0 million. The borrowing base is subject to semi-annual redetermination, based on an assessment of the value of the Company’s proved reserves as determined by a reserve report. As of December 31, 2017, the Company had availability of $101.4 million (after giving effect to $3.6 million of outstanding letters of credit) under its Revolving Credit Facility.

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As amended, borrowings under the Revolving Credit Facility bear interest at one of the following rates, as selected by the Company: (i) the bank’s prime rate in effect, adjusted by an applicable margin of 1.75%–2.75% (the “Base Rate”); or (ii) the London Interbank Offered Rate (“LIBO Rate”), adjusted by an applicable margin of 2.75%–3.75%. The Company may elect to convert outstanding borrowings to a different type and interest rate.

As of December 31, 2017 and 2016, the Company had outstanding borrowings of $95.0 million and $176.8 million, respectively, and outstanding letters of credit of $3.6 million and $3.0 million, respectively, to collateralize the Company’s oil and natural gas transportation agreements and P&A activities under the Revolving Credit Facility. For the years ended December 31, 2017 and 2016, the Company recognized interest expense of $7.4 million and $4.3 million, respectively, related to the Revolving Credit Facility.

As a result of the 2018 Refinancing Transactions, the outstanding balance of the Revolving Credit Facility that would otherwise be classified as the Current portion of debt has been reflected as Long-term debt, net of current portion on the accompanying audited consolidated balance sheets as of December 31, 2017 in accordance with ASC Topic 470-10, Debt (“ASC 470-10”). Refer to Note 20 - Subsequent Events - 2018 Refinancing Transactions for a discussion of refinancing completed by the Company in February 2018.

The Revolving Credit Facility contains certain covenants, as defined in the agreement as of December 31, 2017, including a maximum ratio of total funded debt to EBITDAX, a minimum ratio of current assets to current liabilities, and a minimum asset coverage ratio. As part of the 2018 Refinancing Transactions, the Revolving Credit Facility agreement was amended to include maximum ratio of total funded debt to EBITDAX, maximum ratio of total secured debt to EBITDAX, and a minimum ratio of current assets to current liabilities as covenants. Other restrictive covenants include, but are not limited to, limitations on the Company’s ability to incur indebtedness, declare and pay dividends, make loans or investments, enter into certain hedging agreements, materially change the Company’s business, or undergo a change of control.

As of and during the year ended December 31, 2017, the Company was in compliance with all covenants under the Revolving Credit Facility.

Second Lien Term Loan

In 2014, the Company also established the Second Lien Term Loan, which is secured by a second lien on substantially all of the assets owned by the Company and is subject to the limitations of the Revolving Credit Facility. As of December 31, 2017 and 2016, the Company had outstanding borrowings of $202.5 million and $213.8 million, respectively. For the years ended December 31, 2017 and 2016, the Company recognized interest expense of $26.7 million and $14.7 million, respectively, related to the Second Lien Term Loan.

In February 2018, the Company used a portion of the net proceeds from the private placement offering of $325.0 million aggregate principal amount of 11.0% senior secured second lien notes due 2023 (the “2023 Notes”), resulting in net proceeds of $319.2 million, including initial underwriter fees of $5.8 million (the “2023 Notes Offering”) to repay all the amounts outstanding (including any accrued interest and premiums) under the Second Lien Term Loan, at which time the Second Lien Term Loan was terminated. Refer to Note 20 - Subsequent Events - 2018 Refinancing Transactions for a discussion of the refinancing completed by the Company in February 2018.

Note 12 - Stockholders’ Equity

Prior to the 2015 Equity Offering (refer to Note 1 - Organization and Summary of Significant Accounting Policies - Organization), the Company amended its certificate of incorporation to authorize the issuance of 275,000,000 shares of capital stock consisting of 200,000,000 shares of Class A Common Stock, 50,000,000 shares of $0.001 par value Class B common stock (“Class B Common Stock”), and 25,000,000 shares of Series A Preferred Stock.

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On November 4, 2015, prior to the closing of the 2015 Equity Offering, the then existing members of Energy Ventures GoM Holdings, LLC contributed 100% of their interests to a newly formed limited liability company, EnVen Equity Holdings, LLC (“Equity Holdings”) (the “Equity Holdings Contribution”). At the time of the Equity Holdings Contribution, Energy Ventures GoM Holdings, LLC owned 100% interest in GoM. As a result of the Equity Holdings Contribution, Energy Ventures GoM Holdings, LLC interests in GoM were distributed to Equity Holdings. Immediately following the Equity Holdings Contribution, Energy Ventures GoM Holdings, LLC was converted from a limited liability company to a Delaware corporation and renamed EnVen Energy Corporation (the “Conversion”).

The 2015 Equity Offering, the Equity Holdings Contribution, and the Conversion were contingent upon the First Closing of the Marathon Acquisitions, which closed on December 18, 2015 (refer to Note 2 – Significant Acquisitions of Oil and Natural Gas Properties), therefore, the organization transactions were recognized as of that date.

Class A Common Stock

As part of the 2015 Equity Offering, the Company issued 13,732,925 shares of Class A Common Stock for $10.00 per share. During the year ended December 31, 2016, the Company issued 2,128,779 additional shares of Class A Common Stock to institutional investors for $10.00 per share, the net proceeds of which were used to fund capital expenditures. During the year ended December 31, 2017, the Company only issued Class A Common Stock as part of its employee incentive award plan, discussed in Note 13 - Employee Benefit Plans.

The holders of Class A Common Stock and Class B Common Stock vote together as a single class on all matters and are entitled one vote for each share held.

Class B Common Stock

In 2015, at the time of the Conversion, the Company issued 3,333,333 shares of its Class B Common Stock to the owners of Equity Holdings, resulting in the Company’s Non-controlling Interest in GoM of approximately 19.5% held by Equity Holdings. The Company retained the majority interest ownership (approximately 80.5%) in GoM.

The holders of Class B Common Stock have the right, at their sole discretion, to redeem their interests for cash, or at option of the Company, shares of Class A Common Stock at an exchange ratio of one share of Class A Common Stock for each interest exchanged (“Redemption Rights”). During the year ended December 31, 2017, no members exercised their Redemption Rights.

Series A & Series B Warrants

As a result of the 2015 Equity Offering, the Company also has 13,732,925 Series A Warrants and 13,732,925 Series B Warrants outstanding with each warrant exercisable to purchase 0.07282 shares of Class A Common Stock. The Series A Warrants have an exercise price of $12.50 for one share of Class A Common Stock, and a maximum of 1,000,000 shares of Class A Common Stock may be issued in connection with the exercise of all Series A Warrants. The Series B Warrants have an exercise price of $15.00 for one share of Class A Common Stock, and a maximum of 1,000,000 shares of Class A Common Stock may be issued in connection with the exercise of all Series B Warrants. The warrants are exercisable at any time and expire upon the earlier of: (i) December 8, 2020 or (ii) three years following the closing date of a qualified initial public offering (“QIPO”).

Series A Preferred Stock

On December 30, 2016, the Board designated 9,867,930 shares of the Company’s authorized and unissued shares of preferred stock with a par value of $0.001 per share as Series A Preferred Stock. On the same day, the Company issued 6,159,596 shares of Series A Preferred Stock to selected institutional investors for $12.00 per

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share, resulting in net proceeds of $72.7 million, including underwriter discounts and offering expenses of $1.2 million (the “Series A Preferred Stock Offering”). The net proceeds of the Series A Preferred Stock Offering were used to fund the Shell Acquisition (refer to Note 2 - Significant Acquisitions of Oil and Natural Gas Properties). In connection with the Shell Acquisition, the Company issued an additional 3,708,334 shares of Series A Preferred Stock to Shell in exchange for $44.5 million of additional purchase price consideration.

The Series A Preferred Stock certificate of designation (“COD”) provides holders certain rights and preferential privileges not available to holders of other classes of the Company’s stock. The holders of Series A Preferred Stock are entitled to one vote per share of Class A Common Stock, on an as-converted basis, discussed further below, on all matters to be voted on by the Company’s shareholders.

The holders of Series A Preferred Stock are entitled to receive dividends, at the election of the Board, in cash or in PIK Shares, which are cumulative from the issue date and payable quarterly, in arrears, beginning on December 31, 2016. Historically, the Board has elected to declare PIK Share dividends on a quarterly basis. Additionally, the Series A Preferred Stock receives a preference in an involuntary liquidation of $24.00 per share, plus accrued and unpaid dividends.

The Series A Preferred Stock COD also contains several conversion and redemption features. The Series A Preferred Stock shares are convertible into shares of Class A Common Stock at any time at the option of the holder at the original issue price of $12.00 per share (the “Initial Conversion Price”). Upon the consummation of a QIPO (as defined in the COD), all the shares of the Series A Preferred Stock will automatically convert into a variable number of shares of Class A Common Stock based on the price of the Series A Preferred Stock on the date of conversion (“Conversion Price”). The Conversion Price is based on the Initial Conversion Price and is subject to adjustments for stock dividends, stock splits, stock combinations, and certain issuances of common stock or warrants for less than the Conversion Price. The timing and occurrence of a possible conversion is unknown and contains uncertainties, therefore, neither of the conversion features embody an unconditional obligation.

Additionally, at any time prior to the closing of a QIPO, the Company may offer to redeem shares of Series A Preferred Stock, for cash, at a price equal to the Initial Conversion Price per share, plus any accrued but unpaid dividends. The holders have the right to elect not to have their shares redeemed, therefore, the redemption is not mandatory.

At the time of issuance, the fair value of the Company’s Class A Common Stock did not exceed the Initial Conversion Price, therefore, the conversion features were not considered beneficial and a beneficial conversion feature was not recognized. If a conversion occurs, the Company will evaluate for a beneficial conversion feature.

At the end of each reporting period and each time PIK Share dividends are declared, the Company must evaluate if there is a beneficial conversion feature related to the PIK Share dividends by comparing the fair value of the Company’s Class A Common Stock to the Initial Conversion Price. As of December 31, 2017, the Company recognized a beneficial conversion feature of $2.8 million related to the PIK Share dividends, which is included in the Series A preferred stock dividends line item on the accompanying audited consolidated statements of operations. There was no beneficial conversion feature as of December 31, 2016.

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The following table summarizes the components of the Series A preferred stock dividends presented on the accompanying audited consolidated statements of operations for the periods indicated:

	Year Ended December 31,
	2017		2016
	(In thousands)
Series A preferred stock dividends - paid-in-kind	$	18,794	$	49
Series A preferred stock dividends - beneficial conversion feature		2,796		—
Series A preferred stock dividends	$	21,590	$	49

As of December 31, 2017, there were 11,438,192 outstanding shares of Series A Preferred Stock, including 1,570,262 PIK Shares.

In March 2018, the Company repurchased the Series A Preferred Stock owned by Shell, refer Note 20 - Subsequent Events - Series A Preferred Stock Repurchase for further discussion.

Non-controlling Interest

As a result of the issuance of Class B Common Stock, as discussed above, the Company has the majority interest of and controls its subsidiary, GoM, which is reflected as a consolidated subsidiary in the accompanying audited consolidated financial statements. The remaining ownership interest is reflected as the Non-controlling interest in the accompanying audited consolidated financial statements. GoM is considered a VIE for which the Company is the primary beneficiary, as it is the sole managing member of GoM and has the power to direct the activities most significant to GoM’s economic performance, as well as the obligation to absorb losses and receive benefits that are potentially significant.

The Company’s majority ownership interest percentage is based on the proportionate amount of Class B Common Stock shares outstanding to the total shares outstanding, inclusive of Class A Common Stock, Series A Preferred Stock, and any PIK Share dividends. Therefore, the Non-controlling interest percentage changes if and when shares of Class A Common Stock, Series A Preferred Stock, and PIK Share are issued. As of December 31, 2017 and 2016, the Company owned approximately 89.2% and 88.5%, respectively, of the interest in GoM and the Non-controlling Interest was 10.8% and 11.5%, respectively.

Note 13 - Employee Benefit Plans

Incentive Award Plan

In connection with the 2015 Equity Offering (refer to Note 1 - Organization and Summary of Significant Accounting Policies - Organization), the Company established the EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan (the “Plan”) which authorizes the granting of Restricted Stock, stock options, performance bonuses, and other incentive awards to eligible employees, consultants, and members of the Company’s Board. The Company is authorized to award up to 2,583,301 shares of the Company’s Class A Common Stock pursuant to the Plan. As of December 31, 2017, the Company had 142,340 shares of the Company’s Class A Common Stock available for grant under the Plan. As of December 31, 2017, all incentive awards granted under the Plan have been to employees or members of the Company’s Board.

Restricted stock awards and units. The Company awards Restricted Stock subject to terms, restrictions, and vesting requirements defined in the restricted stock agreements. The Company awards both time-vested and performance-based Restricted Stock. Time-vested Restricted Stock contains a vesting period subject to the Restricted Stock holder continuing employment or service. Generally, time-vested Restricted Stock vests in equal installments on each of the second and third anniversaries of the grant date. Performance-based Restricted Stock vests only if the Company achieves certain performance goals during a predetermined performance period and the Restricted Stock holder remains employed or continues service during the vesting period.

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The Company’s Restricted Stock does not have any post-vesting restrictions, therefore, the fair value of each share of Restricted Stock on the date of grant is determined based on the per share fair value of the Company’s Class A Common Stock on a minority, non-marketable basis. To the extent that there is no recent arm’s-length market transaction, the per share fair value of the Company’s Class A Common Stock is estimated at the grant date of the shares by a third party using an OPM. The inputs to the OPM include assumptions regarding the timing of an expected liquidity event date, equity volatility, risk-free rate, expected dividend yield, and an estimate of the Company’s total equity value as of the grant date of the shares. The assumed timing of an expected liquidity event is based on management’s estimate. As there is currently no active market for the Company’s Class A Common Stock, the Company’s expected equity volatility is determined using the historical volatility of a publicly traded set of peer companies. The risk-free interest rate utilized is based on the interpolated yields of the U.S. Treasury bonds with maturities that commensurate the timing of an expected liquidity event date. The Company has not historically declared or paid Class A Common Stock cash dividends and does not plan to, therefore, the Company does not expect a dividend yield. Refer to Note 5 - Fair Value Measurements for a discussion of the fair value of the Company’s Class A Common Stock.

Absent a recent arm’s-length market transaction, the Company utilized OPM valuations using the following assumptions to determine the fair value of the Company’s Restricted Stock during the year ended December 31, 2017:

Risk-free interest rate	1.3	%
Expected stock price volatility	54.5	%
Expected dividend yield	—	%

The following table presents the Company’s Restricted Stock activity for the periods indicated:

	Restricted Stock			Weighted Average Grant Date Fair Value
Year ended December 31, 2016:
Non-vested at the beginning of the period		511,988		$	10.00
Granted		114,756		$	10.00
Non-vested at the end of the period		626,744		$	10.00
Year ended December 31, 2017:
Non-vested at the beginning of the period		626,744		$	10.00
Granted		1,249,974		$	12.94
Vested		(331,947	)	$	10.28
Non-vested at the end of the period		1,544,771		$	11.95

The aggregate fair value of the Restricted Stock that vested during the year ended December 31, 2017 was $5.0 million. There were no Restricted Stock vestings during the year ended December 31, 2016.

At the time of vesting, Restricted Stock holders may elect to have the Company forfeit a portion of their vested Restricted Stock, based on the Company’s Class A Common Stock fair market value, on their behalf to satisfy their tax withholding requirements. The Restricted Stock that vested during the year ended December 31, 2017 includes 118,407 shares withheld by the Company on behalf of Restricted Stock holders to satisfy $1.9 million of tax withholding requirements. Class A Common Stock withheld or canceled in connection with tax withholding requirements will be available for new grants under the Plan.

The Company recognizes compensation expense related to time-vested Restricted Stock based on a straight-line basis over the vesting period based on the fair value of the Restricted Stock on the date of grant. During the years ended December 31, 2017 and 2016, the Company recognized compensation expense of $5.0 million and

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$2.1 million, respectively, related to time-vested Restricted Stock. As of December 31, 2017, there was $8.9 million of unrecognized compensation expense related to time-vested Restricted Stock, which is expected to be recognized over a weighted average remaining service period of 1.22 years.

The Company recognizes the compensation expense related to performance-based Restricted Stock at the time the performance condition is deemed probable of occurring based on the fair value of the Restricted Stock on the date of grant. As of December 31, 2017, there was $5.8 million of unrecognized compensation expense related to performance-based Restricted Stock. The Company continuously assesses the probability that the performance conditions related to the performance-based Restricted Stock will be achieved and adjusts compensation expense based on its probability assessment. During the year ended December 31, 2017, there have been no changes to the probability of the performance conditions associated with the performance-based Restricted Stock.

Stock options. The Company also awards stock options, which represent the right to purchase Class A Common Stock at a specified price (“Stock Option”). Generally, Stock Options vest in equal installments on each of the first three anniversaries of the grant date. All outstanding Stock Options have an exercise price of $10.00 and expire in 2025.

The fair value of the Stock Options granted is estimated at the date of grant using the Black-Scholes option pricing model. The model utilizes the fair value of the Company’s underlying common stock as well as assumptions regarding the Stock Options expected term, risk-free interest rate, expected volatility of the underlying stock, and expected dividend yield. The Company estimates the fair value of Class A Common Stock using third-party valuations, which use information provided by management and assumptions based on market and economic conditions, including any recent arm’s-length market transactions. Refer to Note 5 - Fair Value Measurements for a discussion of the Company’s Class A Common Stock fair value. The Company lacks historical exercise data to estimate an expected term for the Stock Options, therefore, the expected term of the Company’s Stock Options has been determined utilizing the simplified method for awards, which calculates the expected term as the mid-point between the vesting date and the contractual expiration date of the award. The risk-free interest rate utilized is based on the interpolated yields of the U.S. Treasury bonds with maturities that approximate the Stock Option’s expected term. As there is currently no active market for the Company’s Class A Common Stock, the Company’s expected stock volatility is determined using the historical volatility of a publicly traded set of peer companies. The Company has not historically declared or paid Class A Common Stock cash dividends and does not plan to, therefore, the Company does not expect a dividend yield.

The Company used the following assumptions in the Black-Scholes option pricing model to estimate the fair value of the Company’s Stock Options during the periods indicated:

	Year Ended December 31,
	2017			2016
Risk-free interest rate		1.9	%		1.6	%
Expected stock price volatility		53.0	%		36.0	%
Expected dividend yield		—	%		—	%
Expected term		5.5 years			6.0 years
Fair value of the Company’s Class A Common Stock	$	10.00		$	10.00

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The following table presents the Company’s Stock Option activity for the periods indicated:

	Stock Options		Weighted Average Grant Date Fair Value		Weighted Average Contractual Term
Year ended December 31, 2016:
Outstanding at the beginning of the period		511,988	$	4.48
Granted		114,756	$	3.73
Outstanding at the end of the period		626,744	$	4.34		8.85 years
Exercisable at the end of the period		170,663				8.85 years
Year ended December 31, 2017:
Outstanding at the beginning of the period		626,744	$	4.34
Granted		55,906	$	4.94
Outstanding at the end of the period		682,650	$	4.30		7.85 years
Vested and exercisable at the end of the period		379,578				7.85 years

The Company recognizes compensation expense related to Stock Options on a straight-line basis over the vesting period based on the fair value of the Stock Options on the date of grant. During the years ended December 31, 2017 and 2016, the Company recognized compensation expense of $1.1 million and $0.9 million, respectively, related to Stock Options. As of December 31, 2017, there was $0.9 million of total unrecognized compensation expense related to outstanding Stock Options, which is expected to be recognized over a weighted average remaining service period of 0.45 years.

Defined-Contribution Plan

The Company has a qualified, contributory 401(k) savings plan for all eligible employees. Eligible employees may contribute up to 90% of gross compensation into the plan. The Company can make matching contributions or can contribute discretionary amounts, at their determination at the end of each year. The Company contributed $0.7 million and $0.5 million to the defined contribution plan during the years ended December 31, 2017 and 2016, respectively.

Note 14 - Commitments and Contingencies

Legal Proceedings

From time to time, the Company could be subject to legal actions and claims arising in the ordinary course of business. Liabilities for loss contingencies arising from litigation or claims would be recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. It is the opinion of management that the outcome of these matters will not have a material adverse effect on the Company’s financial position or results of operations.

Asset Retirement Obligations

Marathon Acquisitions. In connection with the Marathon Acquisitions, the Company is required to deposit approximately $100.0 million into escrow accounts to use for future P&A obligation costs assumed in the acquisitions. On the closing date of the acquisition, the Company deposited $30.1 million into escrow to fully fund one of the P&A obligations. The remaining funding obligation began in January 2017 and is being funded quarterly with a percentage of the gross production from the acquired properties until the relevant escrow account reaches $70.0 million. During the year ended December 31, 2017, the Company has deposited $5.5 million into the escrow account to be used for future P&A obligations. The Company records these escrow amounts in the Restricted cash line item on the accompanying audited consolidated balance sheets.

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Other obligations. The BOEM and certain third parties require the Company to post supplemental and performance bonds as a means to ensure its decommissioning obligations, such as the plugging of wells, the removal of platforms and other offshore facilities, the abandonment of offshore pipelines, and the clearing of the seafloor of obstructions. The Company enters into arrangements with surety companies who provide such bonds on its behalf. The Company may be required to provide cash collateral to support the issuance of these bonds and usually pays an annual premium in exchange for the surety’s financial strength to extend the credit. As of December 31, 2017 and 2016, the Company provided surety companies with cash collateral of $41.0 million and $39.6 million, respectively, which is recorded in Restricted cash on the accompanying audited consolidated balance sheets. The surety bond premium is recognized in the Prepaid expenses line item on the accompanying audited consolidated balance sheets and amortized over the life of the surety bond into Interest expense on the accompanying audited consolidated statements of operations. During the years ended December 31, 2017 and 2016, the Company amortized $15.4 million and $9.7 million, respectively, and paid $31.2 million and $9.8 million, respectively, related to the surety bond premiums.

Operating Leases

The Company has several office leases throughout the U.S. which are accounted for as operating leases. The Company leases office space for its headquarters in Houston, Texas, which expires on August 31, 2019. At that time, the Company has the option to renew the lease for another five-year term. The Company also leases office space in Metairie, Louisiana. This lease was amended in February 2017 to extend the expiration date to February 28, 2020. Additionally, in connection with the Marathon Acquisition, the Company assumed a lease obligation from Marathon for field personnel office space in Lafayette, Louisiana. This lease expires September 30, 2018. For the years ended December 31, 2017 and 2016, the Company paid rent expenses of $1.4 million and $1.3 million, respectively, related to these operating leases which is recorded in the G&A expenses on the accompanying audited consolidated statement of operations.

Future lease payments required under these lease agreements as of December 31, 2017 are as follows:

	(In thousands)
2018	$	1,385
2019		912
2020		67
	$	2,364

Drilling Commitments

The Company periodically enters into contractual arrangements to secure drilling rig services in the future, in which case, the Company is required to make future minimum payments to the rig operators. As of December 31, 2017, the Company does not have any drilling rig contracts with minimum commitments that exceed one year. The future payments of these drilling rig commitments are $2.8 million, which represent the Company’s gross contractual obligations. Other joint owners in the properties in which the Company operates will generally be billed their working interest share of such costs.

Note 15 - Concentration Risk

The Company’s production is sold on month-to-month contracts at prevailing prices to a relatively small number of customers, as is customary in the exploration, development, and production business. Historically, the Company has sold a large portion of its oil production to Shell, a related party. However, based on the adequate number of potential other purchasers, the Company does not believe the loss of any major customer would have a significant effect on its results of operations or financial position.

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The following table presents the customers from whom the Company derived 10% or more of its total revenue for the periods indicated:

	Year Ended December 31,
	2017			2016
Shell		84.7	%		68.5	%
Chevron Products Company		*	*		11.4	%

** Less than 10%

Refer to Note 17 - Related Party Transactions for a further discussion of the related party transactions with Shell.

Refer to Note 20 - Subsequent Events for a discussion of the Company’s repurchase of the Series A Preferred Stock from Shell in March 2018.

Note 16 - Income Taxes

On December 22, 2017, the U.S. enacted legislation referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The Tax Act significantly changes U.S. corporate income tax laws beginning, generally, in 2018. These changes include, among others, (i) a reduction of the U.S. corporate income tax rate from a top marginal rate of 35% to a flat rate of 21%, (ii) elimination of the corporate alternative minimum tax, (iii) immediate deductions for certain capital expenditures rather than deductions for depreciation expense over time, (iv) limitation on the tax deduction for interest expense to 30% of adjusted taxable income, (v) limitation of the deduction for net operating losses to 80% of current year taxable income and elimination of net operating loss carrybacks, and (vi) elimination of many business deductions and credits, including the domestic production activities deduction and the deduction for entertainment expenditures. The Company is currently evaluating the impact of the Tax Act but does not expect the provisions of the Tax Act to have a material adverse impact to its future effective tax rate, after-tax earnings, and cash flows.

The tables below represent the remeasurement of deferred tax assets and liabilities at the new corporate tax rate as a result of the Tax Act, which did not impact the Company’s income tax provision or the amounts recorded on our consolidated balance sheets due to the offsetting effect of adjusting the valuation allowance. Due to various estimates included in determining the tax provision, the remeasurement is considered provisional and may be adjusted through subsequent events such as the filing of the Company’s consolidated federal income tax return for the year ended December 31, 2017.

The Company holds the majority of the membership interests in its subsidiary, GoM, which is treated as a partnership for U.S. income tax purposes. For accounting and tax purposes, the GoM partnership activity includes the activities of various single member LLCs, which are wholly-owned by GoM. All references to GoM also include the related activities of such lower-tier entities.

Deferred taxes for GoM activities are recorded based upon the difference between the financial statement basis of the Company’s investment in GoM and the Company’s outside tax basis in its interest in GoM (not including the Company’s share of GoM tax liabilities). As the Company consolidates its financial statements, the financial statement basis in GoM is generally equal to the net equity of GoM less the non-controlling interest in such consolidated net equity of GoM. The Company’s outside tax basis in GoM is computed as the sum of the Company’s cash contributions to GoM plus the Company’s share of allocable items of GoM taxable income less the Company’s share of allocable items of GoM tax deductions, losses, non-deductible expenses, and distributions.

Income tax expense was $14.1 million for the year ended December 31, 2017. The Company did not recognize any income tax expense or benefit during the year ended December 31, 2016. The Company’s income tax

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provision calculated using its effective tax rate of 60.9% differed from amounts computed by applying the U.S. federal income tax rate of 35% to pretax income from continuing operations as a result of the following:

	Year Ended December 31,
	2017			2016
	(In thousands)
Expected tax provision (benefit)	$	8,096		$	(26,413	)
Increase in income taxes resulting from:
Adjustments for non-controlling interest		(903	)		5,030
Return to provision adjustments		64			(1,511	)
State tax expense, net of federal tax benefit		222			—
Permanent differences		87			45
Legislative rate change		11,201			—
Other		(47	)		—
Valuation allowance		(4,625	)		22,849
Income tax provision	$	14,095		$	—

The Company periodically reassesses the realizability of its deferred tax assets and will continue to maintain a valuation allowance against its net deferred tax asset at December 31, 2017. A valuation allowance of $16.8 million and $23.2 million was recorded against its gross deferred tax asset balance as of December 31, 2017 and 2016, respectively.

The following table presents the temporary differences of the Company’s deferred tax assets and deferred tax liabilities:

	December 31, 2017			December 31, 2016
	(In thousands)
Deferred tax assets
Investment in partnership		16,721		$	20,454
Property and equipment		80			188
Stock-based compensation		—			34
Net operating loss carryforwards		—			2,515
Total gross deferred tax assets		16,801			23,191
Valuation allowance		(16,801	)		(23,191	)
Net deferred tax assets	$	—		$	—

A valuation allowance for deferred tax assets, including NOL carryforwards, is recognized when it is more likely than not that all or some portion of the benefit from the deferred tax asset will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding its future taxable income, considering the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include the Company’s current financial position, actual and forecasted results of operations, and tax planning strategies, as well as the current and forecasted business economics of the oil and natural gas industry. Management assesses all available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of objectively verifiable negative evidence is the cumulative loss incurred over the three-year period ending December 31, 2017. Such objective negative evidence limits the Company’s ability to consider various forms of subjective positive evidence, such as its projections of future taxable income. Accordingly, management has not changed its judgment with respect to the need for a valuation allowance against the Company’s net deferred tax asset position. The amount of the deferred tax asset considered realizable, however, could be adjusted in the future.

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The Company’s federal and state income tax returns are not currently under audit by federal or state tax authorities but the Company’s tax returns for the years ended December 31, 2016, 2015, and 2014 remain open to examination. The Company does not believe it has any positions that are not at least more likely than not and as such has not booked a liability for uncertain tax positions.

Note 17 - Related Party Transactions

Redemption Rights

Pursuant to the terms of the amended and restated limited liability company agreement of GoM, the members of GoM have Redemption Rights as discussed in Note 12 - Stockholders’ Equity above. If the members exercise their Redemption Rights, the Company’s interest in GoM will correspondingly increase. As of December 31, 2017, there have been no exercises of Redemption Rights.

Tax Receivable Agreement

In connection with the 2015 Equity Offering (refer to Note 1 - Organization and Summary of Significant Accounting Policies - Organization), the Company entered into a Tax Receivable Agreement (“TRA”) with Equity Holdings, as holder of all limited liability company interests of GoM not held by the Company. Equity Holdings has the right to convert its limited liability company interests in GoM into Class A Common Stock of the Company. Upon such conversions, applicable income tax rules provide certain incremental deductions for tax depreciation, depletion, and amortization to the Company resulting from the conversions. Pursuant to the TRA, the Company is required to remit 85% of the cash tax savings, determined on a with-and-without basis, to Equity Holdings should it convert limited liability company interests in GoM into Class A Common Stock of the Company or payments are accelerated pursuant to the terms of the TRA. The Company has the right to terminate the TRA early, in which case, it would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the TRA, calculated based on certain assumptions and deemed events as set forth in the TRA. In addition, payments due under the TRA will be similarly accelerated following certain mergers or other changes of control. The TRA will remain in effect until the earlier of (a) Equity Holdings or any successor holders exchange all LLC Units of GoM pursuant to the Redemption Rights and the payment of all amounts required to be paid under the Tax Receivable Agreement and (b) the TRA is terminated pursuant to its terms.

The Company’s consolidated balance sheets as of December 31, 2017 and 2016 do not reflect a liability for amounts that could become payable pursuant to the TRA in connection with conversions of limited liability company interests in GoM into Class A Common Stock of the Company. As amounts payable pursuant to the TRA only arise in connection with conversions of limited liability company interests in GoM into Class A Common Stock of the Company, the criteria for reporting a liability on the Company’s consolidated balance sheets as of December 31, 2017 and 2016 have not been met until such conversions have occurred. To date, no such conversions have occurred and, accordingly, no amounts are reflected as a liability on the consolidated balance sheets as of December 31, 2017 and 2016. Additionally, the Company cannot be certain at this time when Equity Holdings may elect to convert its interests into shares of the Company.

Shell Offshore Inc.

On December 30, 2016, the Company completed the Shell Acquisition and the Shell Series A Preferred Stock Offering which resulted in the issuance of 3,708,334 shares of Series A Preferred Stock to Shell for $44.5 million of acquisition purchase price consideration. As of December 31, 2017, the Company has issued 4,298,433 shares of Series A Preferred Stock to Shell, including 590,099 PIK Share dividends, which resulted in Shell owning more than 10% of the Company’s voting interests and qualified Shell as a principal owner of the Company, as defined in ASC Topic 850, Related Party Disclosures.

As discussed in Note 15 - Concentration Risk, for the years ended December 31, 2017 and 2016, the Company sold approximately 85% and 69% of its oil production to Shell. Due to the fact that Shell is a principal owner of

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the Company and is also a major customer, the Company has a related party relationship with Shell and has identified and stated its transactions with Shell as related party transactions on the face of the accompanying audited consolidated financial statements for the years ended December 31, 2017 and 2016.

In March 2018, the Company, along with certain of its equity investors, repurchased all of the shares of Series A Preferred Stock (including the PIK Share dividends issued on March 31, 2018) owned by Shell. As a result of this repurchase, Shell no longer owns any of the Company’s Series A Preferred Stock or has any voting interest and no longer qualifies as a principal owner of the Company. Refer to Note 20 - Subsequent Events for a further discussion of this repurchase transaction.

Bain Capital Credit

Entities affiliated with Bain Capital Credit (“Bain”) hold 39.7% of the Company’s voting interest and three members of the Company’s Board are affiliated with Bain as of December 31, 2017. As of December 31, 2017, Bain was also a 30.5% lender participant in the Company’s Second Lien Term Loan that was terminated in connection with the 2018 Refinancing Transactions and issuance of the 2023 Notes, of which Bain is also a holder. Refer to Note 20 - Subsequent Events for a discussion of refinancing completed by the Company in February 2018.

Note 18 - Supplemental Cash Flow Information

The following table presents a reconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents reported on the accompanying audited consolidated balance sheets to the total amounts reported on the accompanying audited consolidated statements of cash flows:

	December 31, 2017		December 31, 2016
	(In thousands)
Cash and cash equivalents	$	28,848	$	28,477
Current portion of restricted cash(1)		6,789		9,532
Long-term portion of restricted cash(1)		69,783		60,094
Total cash, cash equivalents, restricted cash, and restricted cash equivalents reported on the accompanying audited consolidated statements of cash flows	$	105,420	$	98,103

(1) Represents restricted cash held for future P&A obligations, refer to Note 14- Commitments and Contingencies for a further discussion of these P&A obligations.

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The following table presents non-cash investing and financing activities and supplemental disclosure relating to cash paid for interest for the periods indicated:

	Year Ended December 31,
	2017			2016
	(In thousands)
Non-cash investing and financing activities:
Asset retirement obligations	$	(1,230	)	$	87,784
Expenditures for property and equipment in accounts payable		16,773			(708	)
Notes payable issued for property and equipment		9,550			127
Preferred stock issued for acquisition of oil and natural gas properties - Related party		—			44,500
Series A preferred stock dividends - paid-in-kind		(11,732	)		(31	)
Series A preferred stock dividends - paid-in-kind - Related party		(7,062	)		(18	)
Series A preferred stock dividends - beneficial conversion feature		(1,734	)		—
Series A preferred stock dividends - beneficial conversion feature - Related party	$	(1,062	)	$	—
Supplemental disclosure:
Interest paid on debt	$	(33,242	)	$	(18,526	)

Note 19 - Supplemental Oil and Natural Gas Disclosures (Unaudited)

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development Activities

The following table presents the costs incurred in oil and natural gas acquisition, exploration, and development activities:

	Year Ended December 31,
	2017			2016
	(In thousands)
Proved properties	$	17,550		$	347,265
Unproved properties		1,629			1,738
Total property acquisition costs		19,179			349,003
Acquisition purchase price adjustment(1)		(14,509	)		—
Exploration costs		7,236			1,896
Development costs		95,630			22,028
Total costs incurred	$	107,536		$	372,927

(1) Includes a $14.0 million purchase price adjustment for the Shell Acquisition recorded in the fourth quarter of 2017 and a minimal adjustment recorded during the year ended December 31, 2017 related to a prior year acquisition.

Costs incurred above include ARO costs and revisions of $(1.2) million and $87.8 million for the years ended December 31, 2017 and 2016, respectively.

Proved Reserves

Proved reserves are those quantities of oil and natural 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.

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There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil, natural gas, and NGL prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas ultimately recovered or reserve quantities reported by other entities.

The Company’s reserve estimates as of December 31, 2017, are based on a reserve report prepared by Netherland, Sewell & Associates (“NSAI”) in accordance with the rules and regulations of the SEC by Regulation S-X, Rule 4-10. The Company’s reserve estimates as of December 31, 2016, are based on a reserve report prepared by NSAI and Ryder Scott Company, L.P. in accordance with the rules and regulations of the SEC by Regulation S-X, Rule 4-10. All of the Company’s proved reserves presented below are located in the U.S. Gulf of Mexico. The Company’s estimated proved reserves and the related net revenues and Standardized Measure were determined using the 12-month unweighted arithmetic average of the first-of-the-month price for each month in the period January through December. For the year ended December 31, 2017 and 2016, prices used in the calculations were $51.34 per Bbl and $42.75 per Bbl, respectively, for oil and NGL volumes and $2.98 per MMBtu and $2.49 per MMBtu, respectively, for natural gas volumes. The prices for oil and NGL volumes are adjusted by field for quality, transportation fees, and market differentials and the prices for natural gas volumes are adjusted by field for energy content, transportation fees, and market differentials. Prices are held constant throughout the lives of the oil and natural gas properties. For proved reserves as of December 31, 2017, the average prices adjusted for differentials as discussed above, weighted by production over the remaining lives of the oil and natural gas properties was $50.76 per Bbl for oil and $3.49 per Mcf of natural gas. For proved reserves as of December 31, 2016, the average prices adjusted for differentials as discussed above, weighted by production over the remaining lives of the oil and natural gas properties was $37.67 per Bbl for oil and $2.69 per Mcf of natural gas.

The following table presents a summary of the changes in the Company’s estimated proved oil, natural gas, and NGL reserves during the periods indicated and the Company’s estimated proved developed and undeveloped oil, natural gas, and NGL reserves as of the periods indicated:

	Oil (MBbl)			Natural Gas (MMcf)			NGLs (MBbl)			Total (MBoe)
Proved reserves as of January 1, 2016		24,674			40,088			1,111			32,467
Revisions of previous estimates		(2,038	)		2,174			(2	)		(1,678	)
Extensions and discoveries		228			2,034			25			592
Purchases of minerals in place		25,182			21,512			65			28,832
Production		(4,636	)		(9,243	)		(279	)		(6,456	)
Proved reserves as of December 31, 2016		43,410			56,565			920			53,757
Revisions of previous estimates		2,722			(7,083	)		588			2,130
Extensions and discoveries		5,135			13,454			220			7,597
Production		(7,865	)		(10,316	)		(301	)		(9,885	)
Proved reserves as of December 31, 2017		43,402			52,620			1,427			53,599
Proved developed reserves:
January 1, 2016		20,236			33,619			957			26,797
December 31, 2016		34,949			41,400			807			42,656
December 31, 2017		31,735			37,234			1,042			38,983
Proved undeveloped reserves:
January 1, 2016		4,438			6,469			154			5,670
December 31, 2016		8,461			15,165			113			11,101
December 31, 2017		11,667			15,386			385			14,616

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Revisions of previous estimates. For the years ended December 31, 2017 and 2016, the Company made revisions of 2,130 MBoe and (1,678) MBoe, respectively. Revisions of previous estimates made during the year ended December 31, 2017, were primarily attributable to a positive revision of approximately 3,800 MBoe due to upward proved developed producing performances in several fields, primarily offset by negative revisions of approximately 2,000 MBoe due to three non-core primarily gas fields located in western Gulf of Mexico impacted by low natural gas prices during the year ended December 31, 2017. The revisions of previous estimates made during the year ended December 31, 2016 primarily comprised of 2,177 MBoe of negative revisions due to downward proved developed producing performance in the Lobster field, primarily offset by 600 MBoe of positive revisions relating to unbooked successful well work in the Cognac field.

Extensions and discoveries. For the years ended December 31, 2017 and 2016, extensions and discoveries contributed 7,597 MBoe and 592 MBoe, respectively, to the increase of the Company’s proved reserves primarily as a result of development well work, drilling of proven acreage and new proved undeveloped locations that were added. During the year ended December 31, 2017, extensions and discoveries primarily related to proved reserve additions in the Brutus and Glider fields and in the Main Pass 280 field totaling 5,457 MBoe and 1,157 MBoe, respectively. During the year ended December 31, 2016, extensions and discoveries were attributable to the proved reserve additions in the Cognac field.

Purchases of minerals in place. For the year ended December 31, 2017, the Company’s did not have any purchases of minerals in place. For the year ended December 31, 2016, the Company’s purchases of minerals in place of 28,832 MBoe was primarily attributable to the proved reserves acquired during the Shell Acquisition.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure is the present value, discounted at 10%, of future net cash flows from estimated proved reserves calculated using the 12-month unweighted arithmetic average of the first-of-the-month price for each month in the period January through December (with consideration of price changes only to the extent provided by contractual arrangements). The estimated future net cash flows are reduced by projected future development, production (excluding DD&A and any impairments of oil and natural gas properties), and P&A costs and estimated future income tax expenses.

Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, the Standardized Measure should not be considered to represent the Company’s estimate of the expected revenues or the fair value of our proved oil, natural gas, and NGL reserves.

The following table presents the Standardized Measure relating to estimated proved oil and natural gas reserves:

	Year Ended December 31,
	2017			2016
	(In thousands)
Future cash inflows	$	2,420,950		$	1,810,695
Future production costs		(745,771	)		(667,160	)
Future development costs		(657,202	)		(632,399	)
Future income taxes		(201,878	)		(75,238	)
Future net cash flows		816,099			435,898
10% annual discount for estimated timing of cash flows(1)		(57,003	)		6,516
Standardized Measure	$	759,096		$	442,414

(1) The discount for estimated timing of cash flows is a positive adjustment to the calculation of the Standardized Measure for the year ended December 31, 2016 due to the level of expected future revenue,

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which is impacted significantly by year-end SEC pricing, and the timing of significant amounts of plugging and abandonment expenditures in periods near the end of life of the oil and natural gas properties.

The following table presents the changes in the Standardized Measure relating to estimated proved oil and natural gas reserves for the periods indicated:

	Year Ended December 31,
	2017			2016
	(In thousands)
Standardized Measure at the beginning of the period	$	442,414		$	357,600
Net change in sales prices and production costs related to future production		406,968			(169,511	)
Changes in estimated future development costs		6,499			26,055
Sales of oil, natural gas, and NGLs produced, net of production costs		(338,107	)		(124,658	)
Extensions, discoveries, and other additions, net of future production and development costs		101,443			9,850
Purchases of minerals in place		—			322,531
Revisions of previous quantity estimates		122,003			(35,733	)
Development costs incurred during the period		46,296			18,460
Accretion of discount		51,105			36,175
Net change in income taxes		(92,722	)		1,184
Other		13,197			461
Net increase in Standardized Measure		316,682			84,814
Standardized Measure at the end of the period	$	759,096		$	442,414

Note 20 - Subsequent Events

The Company has evaluated subsequent events from the balance sheet date of December 31, 2017 through May 30, 2018, the date at which this Annual Financial Report for the years ended December 31, 2017 and 2016 was available to be issued and has determined there are no other events to disclose other than those discussed below.

2018 Refinancing Transactions

On February 15, 2018, the Company completed the 2018 Refinancing Transactions, consisting of the 2023 Notes Offering which resulted in net proceeds of $319.2 million, including initial underwriter fees of $5.8 million. The majority of the net proceeds from the 2023 Notes Offering were used to repay all of the outstanding indebtedness (including any accrued interest and premiums) under the Company’s Revolving Credit Facility and Second Lien Term Loan. Consequently, the Second Lien Term Loan was terminated at that time.

Additionally, as part of the 2018 Refinancing Transactions, the Company amended certain terms of its Revolving Credit Facility agreement, which increased the borrowing base to $231.3 million, extended the maturity date to 2022, and decreased all applicable margins related to borrowings under the Revolving Credit Facility by 0.5%.

Prior to the 2018 Refinancing Transactions, the Company would have classified the Revolving Credit Facility and Second Lien Term Loan outstanding balances of $297.5 million, net of $5.3 million in unamortized deferred financing costs and debt discount, as current long-term debt liabilities on the accompanying audited consolidated balance sheets as of December 31, 2017, based on their maturity dates of September 30, 2018 and December 30, 2018, respectively. However, due to the completion of the 2018 Refinancing Transactions, the Company applied the classification guidance related to refinancing transactions in ASC 470-10 and has classified the outstanding balances of the Revolving Credit Facility and Second Lien Term Loan as long-term liabilities on the accompanying audited consolidated balance sheets as of December 31, 2017 because the Company has successfully refinanced its short-term obligations as long-term obligations in the form of the 2023 Notes and has extended the maturity date of its Revolving Credit Facility until 2022.

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Series A Preferred Stock Repurchase

On March 14, 2018, the Company repurchased 2,149,217 shares of its Series A Preferred Stock from Shell at $12.00 per share, for a total price of $25.8 million. Additionally, certain of the Company’s equity investors, including Bain and Adage Capital Partners, L.P., repurchased the remaining 2,229,812 shares (including the PIK Share dividends issued on March 31, 2018) at $12.00 per share. As a result of this repurchase, Shell no longer owns any of the Company’s Series A Preferred Stock or has any voting interest and no longer qualifies as a principal owner of the Company. The Company will not be required to present transactions with Shell as related party transactions on its financial statements for the three months ended March 31, 2018 and going forward.

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Independent Auditor’s Report

To the Boards of Directors

Shell Offshore Inc. and Shell GOM Pipeline Company LLC (“Companies”)

Report on the Financial Statements

We have audited the accompanying statements of revenues and direct operating expenses of the Brutus Glider Properties for the years ended December 31, 2015 and 2014, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Brutus Glider Properties as of December 31, 2015 and 2014 in accordance with accounting principles generally accepted in the United States of America and are not intended to be a complete presentation of the financial position, results of operations, or cash flows of the Brutus Glider Properties.

/s/ Hein & Associates LLP

Houston, Texas

September 27, 2016

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INDEPENDENT AUDITOR’S REVIEW REPORT

To the Boards of Directors

Shell Offshore Inc. and Shell GOM Pipeline Company LLC (“Companies”)

Report on the Financial Statements

We have reviewed the accompanying statements of revenues and direct operating expenses of the Brutus Glider Properties for the nine-month periods ended September 30, 2016 and 2015.

Management’s Responsibility

Management is responsible for the preparation and fair presentation of the interim financial information in accordance with accounting principles generally accepted in the United States of America; this responsibility includes the design, implementation, and maintenance of internal control sufficient to provide a reasonable basis for the preparation and fair presentation of interim financial information in accordance with generally accepted accounting principles.

Auditor’s Responsibility

Our responsibility is to conduct our reviews in accordance with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial information. Accordingly, we do not express such an opinion.

Conclusion

Based on our review, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in accordance with accounting principles generally accepted in the United States of America.

/s/ Hein &Associates LLP

Houston, Texas

April 27, 2017

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BRUTUS GLIDER PROPERTIES

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

(In thousands)

	Nine Months Ended September 30,				Year Ended December 31,
	2016		2015		2015		2014
	(Unaudited)
Related party oil and gas revenues	$	137,656	$	248,355	$	308,823	$	392,553
Related party oil lateral revenues		10,875		12,296		16,583		9,526
Total revenues		148,531		260,651		325,406		402,079
Direct oil and gas operating expenses		86,088		96,065		125,659		130,546
Direct oil lateral operating expenses		890		1,065		1,605		2,054
Total direct operating expenses		86,978		97,130		127,264		132,600
Excess of revenues over direct operating expenses	$	61,553	$	163,521	$	198,142	$	269,479

See notes to statements of revenues and direct operating expenses

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BRUTUS GLIDER PROPERTIES

Notes to Statements of Revenues and Direct Operating Expenses

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

Note 1 - Properties and Basis of Presentation

The accompanying statements represent the interests in the revenues and direct operating expenses of the Brutus Glider oil and natural gas producing properties owned by Shell Offshore, Inc. and produced from Green Canyon Blocks 158, 202 and 204. Included in the direct operating expenses are the Brutus tension leg platform (“TLP”), the Glider subsea production system, and the gas lateral pipeline used to evacuate production from the TLP. The revenues and all direct operating expenses of the Brutus oil lateral owned by Shell GOM Pipeline Company LLC are also represented. The properties are referred to herein as the “Brutus Glider Properties” and are located in the Gulf of Mexico. Shell Offshore, Inc. and Shell GOM Pipeline Company LLC are herein collectively referred to as “Companies”.

The statements of revenues and direct operating expenses have been derived from the Companies’ historical financial records and prepared on the accrual basis of accounting. Revenues and direct operating expenses relate to the historical net revenue interests and net working interests in the Brutus Glider Properties. Oil, gas and condensate revenues are recognized on the sales method when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues are reported net of overriding and other royalties due to third parties. Direct operating expenses include lease operating expenses, production, transportation and all other direct operating costs associated with the properties. Direct operating expenses include $83.2 million and $82.2 million of insurance and other costs allocated by the Companies or their affiliates for years ended December 31, 2015 and 2014. Direct operating expenses include $61.7 million and $60.8 million of insurance and other costs allocated by the Companies for each of the nine months ended September 30, 2016 and 2015. Direct operating expenses do not include corporate overhead, interest expense and income taxes.

The statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Brutus Glider Properties going forward due to the omission of various operating expenses. During the periods presented, the Brutus Glider Properties were not accounted for by the Companies as separate business units. As such, certain costs, such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses and interest expense were not allocated to the Brutus Glider Properties.

Note 2 - Omitted Financial Information

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not available on a property-by-property basis, nor is it practicable to obtain such information in these circumstances. Historically, no allocation of general and administrative, interest expense, corporate taxes, accretion of asset retirement obligations, and depreciation, depletion and amortization was made to the Brutus Glider Properties.

Note 3 - Commitment and Contingencies

On May 11th/12th, 2016 a release of hydrocarbons occurred at the Glider Field located in Green Canyon Block 248 in the Gulf of Mexico. All known material costs associated with this incident as of September 30, 2016 are reflected in the accompanying statements. Government regulators are currently investigating this incident. As a result, the full range of loss arising from this incident cannot be estimated at this time.

F-75

In addition to the incident described above, the Brutus Glider Properties are subject to claims and litigation in the ordinary course of business. The outcome of these matters is not expected to have a material adverse effect on the statement of revenues and direct operating expenses of the Brutus Glider Properties.

Note 4 - Supplemental Oil and Gas Reserve Information (Unaudited)

Proved oil and natural gas reserve quantities are based on internal estimates prepared by EnVen and from information provided by the seller of the Brutus Glider Properties, in accordance with guidelines established by the Securities and Exchange Commission (“SEC”).

However, the reserve studies prior to December 31, 2015 were not available for the Brutus Glider Properties; therefore, the reserve estimates as of December 31, 2014 and 2013 were computed from reserve estimates prepared as of December 31, 2015 by adjusting for pricing and adding back actual production during each period. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Guidelines prescribed in Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) Topic 932 Extractive Industries – Oil and Gas (“ASC Topic 932”), have been followed for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated quantities of oil and gas to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect EnVen’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process.

The values for the December 31, 2015 and 2014 proved reserves were derived based on oil prices of $45.60 per Bbl and $89.90 per Bbl, respectively, and natural gas prices of $3.43 per Mcf and $4.13 per Mcf, respectively. These prices were based on the 12-month arithmetic average first-of-month price for January 2015 through December 2015 and January 2014 through December 2014, respectively. The oil pricing was based on the West Texas Intermediate price and the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.

The following table sets forth information as of and for the years ended December 31, 2015 and 2014 with respect to changes in the Brutus Glider Properties estimated proved reserves:

	Oil (MBbl)			Natural Gas (MMcf)			Total (MBoe)
Proved reserves as of January 1, 2014		28,716			29,540			33,639
Production		(4,200	)		(2,783	)		(4,663	)
Proved reserves as of December 31, 2014		24,516			26,757			28,976
Production		(6,369	)		(5,147	)		(7,227	)
Proved reserves as of December 31, 2015		18,147			21,610			21,749

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Proved developed reserves:
December 31, 2013	22,216	14,394	24,615
December 31, 2014	18,016	11,611	19,952
December 31, 2015	11,647	6,464	12,725
Proved undeveloped reserves:
December 31, 2013	6,500	15,146	9,024
December 31, 2014	6,500	15,146	9,024
December 31, 2015	6,500	15,146	9,024

The following summary sets forth the Brutus Glider Properties future net cash flows relating to estimated proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932:

	Year Ended December 31,
	2015			2014
	(In thousands)
Future cash inflows	$	901,636		$	2,314,527
Future production costs		(231,760	)		(359,025	)
Future development costs		(421,287	)		(421,287	)
Future income taxes		(103,804	)		(540,259	)
Future net cash flows		144,785			993,956
10% annual discount for estimated timing of cash flows		35,674			(163,792	)
Standardized measure	$	180,459		$	830,164

The discount for estimated timing of cash flows is a positive adjustment to the calculation of the standardized measure for the year ended December 31, 2015 due to the level of expected future revenue, which is impacted significantly by year-end SEC pricing, and the timing of significant amounts of plugging and abandonment expenditures in periods near the end of life of the Brutus Glider Properties.

The following table presents the changes in the standardized measure relating to the Brutus Glider Properties estimated proved oil and natural gas reserves for the periods indicated:

	Year Ended December 31,
	2015			2014
	(In thousands)
Standardized measure at the beginning of the period	$	830,164		$	1,047,479
Sales of oil and natural gas produced		(198,142	)		(269,479	)
Net change in sales prices and production costs related to future production		(943,198	)		(21,767	)
Net change in income taxes		335,331			65,010
Accretion of discount		125,677			153,910
Changes in timing and other		30,627			(144,989	)
Standardized measure at the at end of the period	$	180,459		$	830,164

Note 5 - Subsequent Events

On August 29, 2016, Royal Dutch Shell plc, through its affiliate Shell Offshore Inc., announced it has an agreement to sell 100 percent of its record title interest in Gulf of Mexico Green Canyon Blocks 114, 158, 202 and 248, referred to as the Brutus/Glider assets, to EnVen Energy Corporation, through its affiliate EnVen Energy Ventures, LLC. The Brutus/Glider assets include the Brutus Tension Leg Platform (TLP), the Glider subsea production system, and the oil and gas lateral pipelines used to evacuate the production from the TLP. Shell has reserved certain deep operating rights in Green Canyon Blocks 114, 158, and 202. The transaction closed on December 30, 2016.

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Through and including                , 2018 (the 25^th day after the date of this prospectus), all dealers effecting transactions in the Class A common stock, whether or not participating in this offering, may be required to deliver a prospectus. This delivery requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

            Shares

EnVen Energy Corporation

Class A Common Stock

PROSPECTUS

Citigroup

J.P. Morgan

Stifel

BMO Capital Markets

                    , 2018

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

	Amount to Be Paid
SEC registration fee	*
FINRA filing fee	*
Stock exchange listing fee	*
Transfer agent’s fees	*
Printing fees and expenses	*
Legal fees and expenses	*
Accounting fees and expenses	*
Blue Sky fees and expenses	*
Miscellaneous	*
Total	*

* To be completed by amendment.

Each of the amounts set forth above, other than the registration fee and the FINRA filing fee, is an estimate.

Item 14. Indemnification of Directors and Officers

EnVen is incorporated under the laws of Delaware.

Our amended and restated certificate of incorporation and amended and restated bylaws provide that each person who was or is made or is threatened to be made a party or is otherwise involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or she, or a person for whom he or she is the legal representative, is or was a director or an officer of EnVen or, while a director or officer of EnVen, is or was serving at the request of EnVen as a director, officer, employee or agent of another corporation or of a partnership, limited liability company, joint venture, trust, enterprise or non-profit entity, including service with respect to employee benefit plans, shall be indemnified and held harmless by us to the fullest extent authorized by the Delaware General Corporation Law against all liability and loss suffered and expenses (including attorneys’ fees) reasonably incurred by such person.

Section 145 of the Delaware General Corporation Law provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with any threatened, pending or completed actions, suits or proceedings in which such person is made a party by reason of such person being or having been a director, officer, employee or agent to the registrant. The Delaware General Corporation Law provides that Section 145 is not exclusive of other rights to which those seeking indemnification may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors or otherwise.

Pursuant to Section 102(b)(7) of the Delaware General Corporation Law, Article Twelve of our amended and restated certificate of incorporation eliminates the personal liability of a director to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any breach of the director’s duty of loyalty to us or our stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) for unlawful payments of dividends or unlawful stock repurchases, redemptions or other distributions, or (iv) for any transaction from which the director derived an improper personal benefit.

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We have entered into indemnification agreements with each of our current directors and executive officers to provide these directors and executive officers additional contractual assurances regarding the scope of the indemnification set forth in our amended and restated certificate of incorporation and amended and restated bylaws and to provide additional procedural protections. There is no pending litigation or proceeding involving a director or executive officer for which indemnification is sought.

We maintain standard policies of insurance under which coverage is provided (a) to our directors and officers against loss rising from claims made by reason of breach of duty or other wrongful act, and (b) to us with respect to payments which may be made by us to such officers and directors pursuant to the above indemnification provision or otherwise as a matter of law.

The proposed form of underwriting agreement filed as Exhibit 1.1 to this registration statement provides for indemnification of our directors and officers by the underwriters against certain liabilities.

Item 15. Recent Sales of Unregistered Securities

The following sets forth information regarding the securities we have sold within the past three years without registration under the Securities Act of 1933 (the discussion below does not give effect to the Stock Split):

(1) In November 2015, we issued an aggregate of 13,732,925 units in a private offering at a price of $10.00 per unit, to selected institutional investors pursuant to Rule 144A and Regulation S of the Securities Act and in a private placement. Each unit consisted of one share of Class A common stock, one warrant to purchase 0.07282 shares of Class A common stock at an exercise price of $12.50 per share and one warrant to purchase 0.07282 shares of Class A common stock at an exercise price of $15.00 per share. FBR Capital Markets & Co. acted as the initial purchaser and placement agent. This offering resulted in net proceeds of $125.7 million, including initial purchaser discounts and offering expenses of $7.6 million.

(2) On December 30, 2016, we issued 6,159,596 shares of Series A preferred stock to institutional investors for $12.00 per share, resulting in net proceeds of $72.7 million, including initial purchaser discounts and offering expenses of $1.2 million.

(3) On February 15, 2018, Energy Ventures GoM LLC, a direct subsidiary of EnVen Energy Corporation, and EnVen Finance Corporation, a wholly-owned subsidiary of Energy Ventures GoM LLC, issued $325 million in aggregate principal amount of the 2023 Notes resulting in net proceeds of approximately $317.0 million. The 2023 Notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside the United States in compliance with Regulation S under the Securities Act.

Item 16. Exhibits and Financial Statement Schedules

(a) The following exhibits are filed as part of this registration statement:

Exhibit Number	Description
1.1*	Form of Underwriting Agreement
3.1*	Form of Amended and Restated Certificate of Incorporation of EnVen Energy Corporation
3.2*	Form of Amended and Restated Bylaws of EnVen Energy Corporation
4.1*	Form of Common Stock Certificate of EnVen Energy Corporation
4.2	Senior Secured Second Lien Notes Indenture, dated as of February  15, 2018, among Energy Ventures GoM LLC, EnVen Finance Corporation, the guarantors party thereto and Wilmington Trust, National Association, as Trustee and Collateral Agent, relating to the 11.000% Senior Secured Second Lien Notes due 2023

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Exhibit Number	Description
4.3*	Form of Warrant Certificate of EnVen Energy Corporation
5.1*	Opinion of Davis Polk & Wardwell LLP
10.1*	Tax Receivable Agreement, dated as of November 6, 2015, among EnVen Energy Corporation, Energy Ventures GoM LLC, EnVen Equity Holdings LLC and each of the members party thereto
10.2*	Second Amended and Restated Limited Liability Company Agreement of Energy Ventures GoM, LLC, effective as of December 30, 2016
10.3	Registration Rights Agreement, dated as of November 6, 2015, among EnVen Energy Corporation and EnVen Equity Holdings LLC
10.4	Registration Rights Agreement, dated as of November 6, 2015, among EnVen Energy Corporation, FBR Capital Markets  & Co., EIG Tarpon Holdings, LLC and certain entities associated with Bain Capital
10.5	Registration Rights Agreement Extension and Amendment Agreement, dated as of December  22, 2016, among EnVen Energy Corporation, Adage Capital Partners, L.P. and certain entities associated with Bain Capital
10.6	Registration Rights Agreement, dated as of December 30, 2016, among EnVen Energy Corporation and the investors party thereto
10.7	Amended and Restated Credit Agreement, dated as of December 30, 2016, among Energy Ventures GoM LLC, EnVen Energy Corporation, the lenders party thereto and Bank of Montreal, as Administrative Agent
10.8	First Amendment to Amended and Restated Credit Agreement, dated as of January  26, 2018, among Energy Ventures GoM LLC, EnVen Energy Corporation, the other guarantors party thereto, the lenders party thereto and Bank of Montreal, as Administrative Agent
10.9	Second Lien Security Agreement, dated as of February  15, 2018, among Energy Ventures GoM LLC, EnVen Finance Corporation, the grantors party thereto and Wilmington Trust, National Association, as Collateral Agent
10.10	Intercreditor Agreement, dated as of February  15, 2018, among Energy Ventures GoM LLC, the other grantors party thereto, Bank of Montreal, as Senior Representative and Wilmington Trust, National Association, as Collateral Agent
10.11*	EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan
10.12*	First Amendment to the EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan, dated October 1, 2018
10.13*	Employment Agreement, dated November 6, 2015, between EnVen Energy Corporation and David M. Dunwoody. Jr.
10.14*	Employment Agreement, dated November 6, 2015, between EnVen Energy Corporation and Steven A. Weyel
10.15*	Employment Agreement, dated as of March 16, 2016, between EnVen Energy Corporation and John P. Wilkirson
21.1	Subsidiaries of the registrant
23.1	Consent of Independent Registered Public Accounting Firm—Ernst & Young LLP
23.2	Consent of Independent Auditor—Hein & Associates LLP
23.3	Awareness Letter of Independent Auditor—Hein & Associates LLP

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Exhibit Number	Description
23.4*	Consent of Davis Polk & Wardwell LLP (included in Exhibit 5.1)
23.5	Consent of Netherland, Sewell & Associates, Inc.
23.6	Consent of Ryder Scott Company, L.P.
24.1	Power of Attorney (included on signature page)
99.1	Summary Reserve Report of Netherland, Sewell & Associates, Inc. as of December 31, 2016
99.2	Summary Reserve Report of Ryder Scott Company, L.P. as of December 31, 2016
99.3	Summary Reserve Report of Netherland, Sewell & Associates, Inc. as of December 31, 2017
99.4	Summary Reserve Report of Netherland, Sewell & Associates, Inc. as of July 31, 2018

* To be filed by amendment.

(b) The following financial statement schedule is filed as part of this registration statement:

Item 17. Undertakings

The undersigned registrant hereby undertakes:

(a) The undersigned registrant hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.

(b) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions referenced in Item 14 of this registration statement, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer, or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered hereunder, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

(c) The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-4

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 2nd day of October, 2018.

EnVen Energy Corporation
By:	/s/ Steven A. Weyel
	Name:	Steven A. Weyel
	Title:	Chief Executive Officer

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POWER OF ATTORNEY AND SIGNATURES

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Steven A. Weyel, John P. Wilkirson and Jeffrey A. Starzec, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and any and all additional registration statements pursuant to Rule 462(b) of the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the SEC, granting unto each said attorney-in-fact and agents full power and authority to do and perform each and every act in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or either of them or their or his or her substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Steven A. Weyel	Chief Executive Officer (principal executive officer)	October 2, 2018
Steven A. Weyel
/s/ John P. Wilkirson	Chief Financial Officer (principal financial officer)	October 2, 2018
John P. Wilkirson
/s/ Kayla D. Baird	Chief Accounting Officer (principal accounting officer)	October 2, 2018
Kayla D. Baird
/s/ Jon A. Jeppesen	Director	October 2, 2018
Jon A. Jeppesen
/s/ Kenneth R. Olive, Jr.	Director	October 2, 2018
Kenneth R. Olive, Jr.
/s/ Richard Sherrill	Director	October 2, 2018
Richard Sherrill
/s/ Andrew Hailey	Director	October 2, 2018
Andrew Hailey
/s/ John Ezekowitz	Director	October 2, 2018
John Ezekowitz
/s/ Christopher Linneman	Director	October 2, 2018
Christopher Linneman

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