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As confidentially submitted to the Securities and Exchange Commission on June 29, 2018

This draft registration statement has not been publicly filed with the Securities and Exchange Commission and all information

herein remains strictly confidential.

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

  $           $        

 

 

(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.

 

 

 


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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 JUNE 29, 2018

PRELIMINARY PROSPECTUS

            Shares

 

 

LOGO

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 “                .”

 

 

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 23.

 

 

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.

 

 

 

 

 

                    , 2018


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TABLE OF CONTENTS

 

 

 

 

 

 

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 23 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 measures 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 arrangements, discounted at 10%. The PV-10 value of our proved reserves is derived from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure and is equal to the standardized measure of discounted future net cash flows at the applicable date, but before deducting future income taxes, discounted at 10%. Our proved reserve PV-10 value also includes cash inflows from the future net revenues related to third-party production handling arrangements, discounted at 10%.

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 the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves. Moreover, 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.

 

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Our management believes that the presentation of PV-10 is useful 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 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.

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.

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

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.

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.

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.

 

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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.

MMBoe. Million barrels of oil equivalent.

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.

 

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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.

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.

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.

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.

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.

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.

 

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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.

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 9 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 developing and acquiring producing deepwater assets that we believe have untapped development opportunities and will provide strong cash flow and lower-risk development with significant exploration potential. This strategy allows us to benefit from the favorable geologic and economic characteristics of the deepwater U.S. Gulf of Mexico.

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, much of our acreage is prospective for oil and natural gas production from multiples zones, or stacked-pay, which, using the latest seismic and drilling technology, provides us with additional development and production enhancement opportunities within existing and future wellbores. Our portfolio of assets includes multiple years of already identified and potentially high-return projects. Among other things, these projects include lower risk recompletions, tie-backs, sidetracks and new drills, all of which are located near the midstream infrastructure we own. In addition, we expect to convert, without the need to spend incremental capital, a material portion of our 2P and 3P reserves to 1P reserves, and grow our production.

In addition to our existing portfolio of assets, we continue to actively target new leases and third-party assets adjacent to the infrastructure we own. We have a proven track record of executing transformative acquisitions, having twice doubled our production and reserves in two asset transactions over the past three years. Targeting assets near infrastructure we own allows us to leverage our portfolio of host production facilities to increase operational efficiency and reduce development costs. Our focus on the deepwater region also provides us with additional opportunities to acquire 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 March 31, 2018, we held 66 leases in the U.S. Gulf of Mexico spanning approximately 310,306 gross acres (231,558 net), owned and operated 27 offshore platforms and had an ownership interest in 13 non-operated offshore platforms. For the year ended December 31, 2017, over 85% of our proved reserves, production and Adjusted EBITDA were generated by assets located in the deepwater region, which is subject to less storm risk than shelf properties. As of March 31, 2018, approximately 74% of our leasehold interests were “held by production,” and we had an average working interest of approximately 79% for our operated wells and approximately 31% for our non-operated wells. For the three months ended March 31, 2018, our daily production averaged 28.9 MBoe/d, of which approximately 80% was oil and approximately 82% was generated by assets we



 

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operate. This represents an increase of approximately 7% over our 2017 average daily production of 27.1 MBoe/d. For the year ending December 31, 2018, we expect our average daily production will be 28.0 MBoe/d to 32.0 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 three months ended March 31, 2018, we generated net income and Adjusted EBITDA of $7.7 million and $105.1 million, respectively. See “—Summary Historical Consolidated Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA” for a reconciliation of Adjusted EBITDA to net income (loss).

As of December 31, 2017, we had total proved reserves of 53.6 MMBoe, total probable reserves of 22.8 MMBoe and total possible reserves of 22.2 MMBoe, with approximately 73% of our total proved reserves, approximately 65% of our total probable reserves and approximately 61% of our total possible reserves being considered developed. As of December 31, 2017, the PV-10 value of our proved reserves was $1,017.2 million (including $76.6 million of restricted cash on the balance sheet as of December 31, 2017), the PV-10 value of our probable reserves was $517.8 million and the PV-10 value of our possible reserves was $460.0 million. 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 December 31, 2017, based on a fully-engineered reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. In addition, the table shows our average daily production across our fields for the three months ended March 31, 2018.

 

     Average Daily
Production for
the three months
ended March 31,
2018
    Proved Reserves     Probable Reserves     Possible Reserves  
     (Boe/d)      % Oil     Total
(MMBoe)
    PV-10(1)
(In millions)
    Total
(MMBoe)
    PV-10
(In millions)
    Total
(MMBoe)
    PV-10
(In millions)
 

Brutus field

     7,509        85     19.2     $ 389.9       6.7     $ 140.7       3.9     $ 125.7  

Glider field

     6,547        89     8.7       237.6       4.8       163.9       3.7       93.0  

Lobster field

     4,004        87     5.8       102.4       2.1       44.0       3.5       57.6  

Petronius field

     3,508        72     3.9       53.7       2.0       36.1       2.0       32.6  

Cognac field

     1,103        74     4.0       62.1       2.0       29.2       4.1       37.9  

Other fields

     6,257        66     12.0       74.8       5.2       90.9       5.0       84.7  

Production handling arrangements(2)

          —         20.1       —         13.0       —         28.5  

Restricted cash(3)

            76.6          
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

     28,928        80     53.6     $ 1,017.2       22.8     $ 517.8       22.2     $ 460.0  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Percentage developed reserves

          73     74     65     60     61     65

 

(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



 

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  effects of income taxes on future net revenues, discounted at 10%, but includes the future net revenues from production handling agreements, discounted at 10%, and restricted cash as of December 31, 2017. 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) Production handling arrangements relate to estimated future net revenues contracted with third parties under evergreen arrangements. The PV-10 values vary by reserve category based on NSAI’s assumption for contract termination. Under existing agreements, $20.1 million for proved reserves is expected to be received through December 31, 2019; an additional $13.0 million for probable reserves is expected to be received from January 1, 2020 through December 31, 2025; and an additional $28.5 million for possible reserves is expected to be received from January 1, 2026 through December 31, 2032.
(3) Restricted cash represents amounts reserved as cash collateral for certain bonding requirements and amounts held in escrow for plug and abandonment obligations as of December 31, 2017.

In the past, we have consistently been able to outperform our initial reserve estimates, with actual production quantities and PV-10 values exceeding those originally represented in our third-party reserve reports. Because SEC methodology requires a 90% likelihood of success for proved reserves, it is common to have actual outcomes that exceed the initial proved booking. Between 2015 and 2017, five wells were drilled and brought on production, but only two were booked as PUDs in our reserve reports prior to drilling. The two PUD bookings included approximately 1.4 MMBoe, but as of December 31, 2017, inclusive of historical production, the five wells represented total proved, total probable and total possible reserves of 5.0 MMBoe, 1.2 MMBoe and 1.7 MMBoe, respectively. Collective results as of December 31, 2017 show total proved, total probable and total possible volumes were 3.5, 4.3, and 5.5 times higher, respectively, than pre-drill PUD volumes as reflected in our reserve reports. 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 substantial unbooked project inventory under and adjacent to our current properties. Of our planned capital program in 2018 and 2019, approximately 50% is dedicated to developing resources that are currently outside of our booked reserves. Recent results at our Lobster field are evidence of these unbooked reserves. In June 2018, we discovered in our Lobster A-2 well over 350 feet of net pay sands in multiples intervals, the majority of which is beneath the field’s current production zone. These deeper intervals represent significant potential reserves that are currently not included in our reserve report. Including these near-term projects, we have identified over 60 projects on our existing acreage that we expect will provide significant reserve potential as we enter the next decade. Out of these 60 identified projects, many have been partially de-risked due to successful drilling efforts in nearby intervals that are comparable to those in the identified projects. Moreover, the vast majority of these projects are located within relatively short distances to our infrastructure, which would allow for shorter development and production lead times should reserves be discovered.

Our Capital Program

Our total 2018 and 2019 capital program of $450 million to $500 million, excluding nominal annual P&A of $20 million to $30 million, is primarily focused on the continued development of our operated Brutus, Glider, Lobster and Cognac fields. These four fields account for approximately 66% of the total capital program over that period. We estimate that these projects have the potential to contribute 16.0 MBoe/d to 22.0 MBoe/d of net production as of year-end 2019 and substantially increase our reserves. See “Business—Our Oil and Natural Gas Properties—Significant Properties” for a discussion of the current and planned projects in Brutus, Glider, Lobster and Cognac fields. 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



 

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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. In addition, approximately 30% of our capital budget is allocated to either properties we operate or cost centers we control, with the remaining approximately 4% allocated to non-operated drill wells and recompletions. 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. However, as approximately 82% of our daily production for the three months ended March 31, 2018 was generated by assets 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 program but instead expect, assuming current oil and natural gas prices, to fully fund the program with cash on hand and internally generated cash flows.

 

 

LOGO

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



 

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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.

 

LOGO

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 is 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.

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. 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 3D 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 independents, including ConocoPhillips, Marathon Oil, Freeport-McMoRan, and Apache have either abandoned their U.S. Gulf of Mexico programs altogether or divested assets. Of the majors 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 the current commodity price environment has motivated large operators 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 transformational acquisitions and we will continue to proactively seek to acquire what we believe to be under-exploited deepwater opportunities from highly regarded operators. In December 2015, we approximately doubled our production and proved developed reserves through a transaction with Marathon Oil Corporation (“Marathon”). In December 2016, we again approximately doubled our production and proved developed reserves through a transaction with Shell Offshore Inc. (“Shell”). We



 

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believe that additional opportunities like these exist in the market today in the deepwater region of the U.S. Gulf of Mexico as companies prioritize their portfolios with many larger operators choosing to focus on larger, more capital-intensive projects in the ultra-deepwater. Since the closing of the Shell acquisition in December of 2016, we have reviewed approximately 20 potential acquisitions under non-disclosure agreements. We are proactively pursuing acquisitions of operated assets that (i) have quality proved developed producing reserves and further development and exploitation potential, (ii) allow us to control operating costs and associated P&A liabilities, (iii) have accompanying infrastructure for offtake and processing, or which leverage our existing infrastructure, and (iv) have oil-weighted production, particularly in geologic regions where our multidisciplinary technical team believes there are untapped hydrocarbon resources. 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 de-risked 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 81% of our total proved reserves, as of December 31, 2017, and approximately 80% of our daily production, for the three months ended March 31, 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 by producers in many onshore basins such as the Permian. For the year ended December 31, 2017, our Adjusted EBITDA margin and net income margin were approximately 69% and approximately 2%, respectively. For the three months ended March 31, 2018, our Adjusted EBITDA margin and net income margin were approximately 71% and approximately 5%, 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 Gulf of Mexico that affords us operational differentiation and opportunity access. 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 facility, 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 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. 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. We currently have eight production handling agreements in place that generated $14.8 million of additional revenue during the year ended December 31, 2017. The third party production processing agreements require minimal incremental operating cost by the Company.    

 

   

Multi-year inventory of attractive lower-risk drill bit projects. Our geological and geophysical professionals have identified more than 60 growth projects across our portfolio that we believe



 

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represent multiple years of inventory of lower geologic risk development and exploration opportunities. In the quarter ended March 31, 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 stacked-pay development opportunities.

 

    Experienced and safe deepwater operator with operating control over a majority of our assets. We operate properties that generated approximately 79% of our production and accounted for approximately 88% of our proved reserves as of December 31, 2017. Over 95% of our capital expenditure budget for 2018 and 2019 is allocated to either properties that we operate or cost centers that we control. Operational control allows us to dictate the selection and pace of development projects, better manage our P&A liabilities, institute our safety and environmental programs and practices and more closely control risks and costs. 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. During this same period, our company-wide ratio of reportable incidents decreased by approximately 40%. 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 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 March 31, 2018, the ratio of our total debt to Adjusted EBITDA for the last 12 months ended March 31, 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 March 31, 2018, our cash balance and availability under our undrawn Revolving Credit Facility (as defined below) (after giving effect to $3.6 million of outstanding letters of credit), subject to the borrowing base of $231.3 million at the time, was $283.0 million. In June 2018, as a result of a semi-annual redetermination, we increased our borrowing base to $275.0 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. In 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.


 

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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 arrangements represent significant incremental revenue at no incremental cost to the company. 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 will 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 base 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.


 

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    Proactively manage our P&A obligations and bonding requirements. As of December 31, 2017, 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. As a result, the majority of our historic 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 $20 million to $30 million per year in 2018 and 2019 to plug and abandon additional shelf fields that have reached end of life. Given the long-remaining life of our deepwater fields, we do not anticipate any P&A expenditures on proved reserves related to our deepwater facilities before 2024. As of March 31, 2018, we had $145 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, since we operated approximately 88% of our proved reserves as of December 31, 2017, we are able to manage the majority of our P&A obligations. 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 March 31, 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.

 

 

LOGO



 

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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 Restatement 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



 

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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.

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 us 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

The declaration, amount and payment of any future dividends on shares of Class A common stock will be at the sole discretion of our board of directors and we may reduce or discontinue entirely the payment of any such dividends at any time. 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.”

 

Proposed NYSE symbol

“             ”

 

Risk factors

See “Risk Factors” beginning on page 23 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, 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 March 31, 2018 at a weighted average exercise price of $        per share; and

 

                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”).


 

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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 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 March 31, 2018 and the summary consolidated statement of operations data, statement of cash flows data and other financial data for each of the three months ended March 31, 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)

   Three months ended
March 31,
    Year ended
December 31,
 
   2018     2017     2017     2016  

Statement of operations

        

Total revenues(1)

   $ 147,347     $ 114,879     $ 434,411     $ 203,319  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses(1):

        

Lease operating expenses

     21,473       32,718       97,560       67,918  

Workover, repair, and maintenance expenses

     3,671       4,096       18,642       12,754  

Transportation, gathering, and processing costs(2)

     2,735       —         —         —    

Depreciation, depletion, and amortization

     47,409       47,964       170,372       104,584  

General and administrative expenses

     11,534       8,654       42,397       35,078  

Accretion of asset retirement obligations

     8,438       7,485       31,392       21,669  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

   $ 95,260     $ 100,917     $ 360,363     $ 242,003  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ 52,087     $ 13,962     $ 74,048     $ (38,684
  

 

 

   

 

 

   

 

 

   

 

 

 

Other (expense) income:

        

Interest expense

     (24,116     (15,041     (60,307     (31,545

(Loss) gain on derivatives, net

     (13,752     22,814       5,020       (9,153

Interest income

     1,172       1,040       4,370       3,916  

Loss on extinguishment of long-term debt

     (4,012     —         —         —    

Loss on fair value of 11.00% Senior notes due 2023

     (3,250     —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other (expense) income

   $ (43,958   $ 8,813     $ (50,917   $ (36,782
  

 

 

   

 

 

   

 

 

   

 

 

 

Income tax expense

     416       —         14,095       —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 7,713     $ 22,775     $ 9,036     $ (75,466
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to non-controlling interest

   $ 783     $ 3,716     $ 2,581     $ (14,371
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to EnVen Energy Corporation

   $ 6,930     $ 19,059     $ 6,455     $ (61,095
  

 

 

   

 

 

   

 

 

   

 

 

 

Series A preferred stock dividends

     (6,535     (4,392     (21,590     (49
  

 

 

   

 

 

   

 

 

   

 

 

 


 

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(In thousands, except for the number of shares outstanding and per
share amounts)

   Three months ended
March 31,
    Year ended
December 31,
 
   2018     2017     2017     2016  

Net income (loss) attributable to EnVen Energy Corporation common stockholders

   $ 395     $ 14,667     $ (15,135   $ (61,144

Net income (loss) per common share—basic

   $ 0.02     $ 0.89     $ (0.95   $ (4.13

Net income (loss) per common share—diluted

   $ 0.02     $ 0.68     $ (0.95   $ (4.13

Weighted average common shares outstanding—basic

     16,132,490       15,861,704       15,912,950       14,795,005  

Weighted average common shares outstanding—diluted

     16,942,961       27,708,099       15,912,950       14,795,005  

Statement of cash flows data

        

Net cash provided by operating activities

   $ 76,161     $ 38,775     $ 191,482     $ 26,954  

Net cash used in investing activities

   $ (34,089   $ (13,459   $ (84,759   $ (243,631

Net cash (used in) provided by financing activities

   $ (13,645   $ (34,154   $ (99,406   $ 242,633  

Other financial data

        

Adjusted EBITDA(3)

   $ 105,142     $ 73,060     $ 300,125     $ 92,707  

 

(In thousands)    As of
March 31,
2018
     As of
December 31,
2017
 

Balance sheet data

     

Cash and cash equivalents(4)

     55,305        28,848  

Accounts receivable

     65,000        68,305  

Other current assets

     25,702        28,373  
  

 

 

    

 

 

 

Total current assets

   $ 146,007      $ 125,526  
  

 

 

    

 

 

 

Property and equipment, net

     676,584        691,490  

Other non-current assets

     129,976        126,025  
  

 

 

    

 

 

 

Total assets

   $ 952,567      $ 943,041  
  

 

 

    

 

 

 

Current liabilities

     124,447        140,375  

Other non-current liabilities

     595,191        552,281  
  

 

 

    

 

 

 

Total liabilities

   $ 719,638      $ 692,656  
  

 

 

    

 

 

 

Total equity

     232,929        250,385  
  

 

 

    

 

 

 

Total liabilities and equity

   $ 952,567      $ 943,041  
  

 

 

    

 

 

 

 

(1) The total revenues and total operating expenses for the three months ended March 31, 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 $2.7 million of transportation, gathering, and processing costs for the three months ended March 31, 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) 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.
(4) Does not include current portion of restricted cash of approximately $6.8 million and $9.5 million as of March 31, 2018 and 2017, respectively, and approximately $6.8 million and $9.5 million as of December 31, 2017 and 2016, respectively, reserved as cash collateral for certain bonding requirements and amounts held in escrow for plug and abandonment obligations.


 

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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.

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.

 

     Three months ended
March 31,
    Year ended
December 31,
 
(In thousands)    2018     2017     2017     2016  

Net income (loss) reconciliation to Adjusted EBITDA:

        

Net income (loss)

   $ 7,713     $ 22,775     $ 9,036     $ (75,466

Depreciation, depletion, and amortization

     47,409       47,964       170,372       104,584  

Income tax expense(1)

     416       —         14,095       —    

Accretion of asset retirement obligations

     8,438       7,485       31,392       21,669  

Non-cash stock-based compensation(2)

     1,834       867       6,066       3,057  

Interest expense(3)

     24,116       15,041       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)

     3,250       —         —         —    

Loss (gain) on derivatives, net

     13,752       (22,814     (5,020     9,153  

Cash (paid) received for derivative settlements, net

     (4,692     2,748       18,047       1,601  

Non-cash interest income(6)

     (1,106     (1,006     (4,170     (3,793

Other expenses (7)

     —         —         —         357  
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 105,142     $ 73,060     $ 300,125     $ 92,707  

 

(1) For the three months ended March 31, 2018, we recognized an effective tax rate of 5.1% compared to 0% for the three months ended March 31, 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.


 

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(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 three months ended March 31, 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 December 31, 2017.

The reserve estimates attributable to our assets presented in the table below are based on a fully-engineered reserve report included elsewhere in this prospectus prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), using SEC pricing as of December 31, 2017. The reserve report was prepared in accordance with the rules and regulations of the SEC. A summary of such reserve report is included elsewhere in this prospectus.

The Standardized Measure and PV-10 values shown in the table 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” and “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
December 31,
2017(1)
 

Estimated proved developed reserves:

  

Oil (MBbls)

     31,735  

Natural gas (MMcf)

     37,234  

NGLs (MBbls)

     1,042  

Total (MBoe)

     38,982  

Estimated proved undeveloped reserves:

  

Oil (MBbls)

     11,667  

Natural gas (MMcf)

     15,386  

NGLs (MBbls)

     385  

Total (MBoe)

     14,616  

Estimated proved reserves:

  

Oil (MBbls)

     43,402  

Natural gas (MMcf)

     52,620  

NGLs (MBbls)

     1,427  

Total (MBoe)

     53,599  

Estimated probable reserves:

  

Oil (MBbls)

     17,498  

Natural gas (MMcf)

     28,693  

NGLs (MBbls)

     515  

Total (MBoe)

     22,795  

Estimated possible reserves:

  

Oil (MBbls)

     17,905  

Natural gas (MMcf)

     21,025  

NGLs (MBbls)

     756  

Total (MBoe)

     22,165  

Proved reserve PV-10 value (in thousands)(2)(3)

   $ 940,573  

Standardized Measure (in thousands)

   $ 759,096  

Probable reserve PV-10 value (in thousands)(2)(3)

   $ 517,800  

Possible reserve PV-10 value (in thousands)(2)(3)

   $ 460,061  


 

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(1) Estimates of reserves as of December 31, 2017 were prepared using SEC pricing as of December 31, 2017. The unweighted arithmetic average first-day-of-the-month prices were $51.34 per Bbl for oil and NGL volumes and $2.98 per MMBtu for natural gas volumes at December 31, 2017, adjusted by field for quality, transportation fees and market differentials. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they 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 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 arrangements, 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) Production handling arrangements relate to estimated future net revenues contracted with third parties under evergreen arrangements. The PV-10 values vary by reserve category based on NSAI’s assumption for contract termination. Under existing agreements, $20.1 million for proved reserves is expected to be received through December 31, 2019; an additional $13.0 million for probable reserves is expected to be received from January 1, 2020 through December 31, 2025; and an additional $28.5 million for possible reserves is expected to be received from January 1, 2026 through December 31, 2032.

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 arrangements, discounted at 10%. The PV-10 value of our proved reserves is derived from the Standardized Measure, the most directly comparable GAAP financial measure and is equal to the Standardized Measure at the applicable date, but before deducting future income taxes, discounted at 10%. Our proved reserve PV-10 value also includes cash inflows from the future net revenues related to third-party production handling arrangements, discounted at 10%. 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 Standardized Measure do not purport to present the fair value of our oil and natural gas reserves. Moreover, 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. 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



 

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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 “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 December 31, 2017:

 

(In thousands)    As of
December 31,
2017
 

Proved reserve PV-10 value

   $ 940,573  

Present value of future income taxes discounted at 10%

     161,359  

Present value of future net revenues related to third-party production handling arrangements discounted at 10%(1)

     20,118  
  

 

 

 

Standardized Measure

   $ 759,096  

 

(1) Production handling arrangements relate to estimated future net revenues that we will receive related to arrangements with third parties during the years ended December 31, 2018 and 2019.


 

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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.”

 

     Three months ended
March 31,
     Year ended
December 31,
 
        2018            2017         2017      2016  

Net production volumes:

           

Oil (MBbls)

     2,085        2,137        7,865        4,636  

Natural gas (MMcf)

     2,647        3,001        10,316        9,243  

NGLs (MGals)

     3,245        2,565        12,649        11,709  

Total (MBoe)

     2,603        2,698        9,885        6,455  

Average net production (MBoe/d)

     28.9        30.0        27.1        17.7  

Average sales prices:

           

Oil, excluding effects of derivatives (per Bbl)

   $ 63.01      $ 47.31      $ 48.66      $ 37.18  

Oil, including effects of derivatives (per Bbl)(1)

   $ 60.54      $ 48.34      $ 50.67      $ 37.68  

Natural gas, excluding effects of derivatives (per Mcf)

   $ 3.67      $ 3.11      $ 2.93      $ 2.12  

Natural gas, including effects of derivatives (per Mcf)(1)

   $ 3.84      $ 3.29      $ 3.15      $ 2.18  

NGLs (per Bbl)

   $ 30.69      $ 19.88      $ 18.21      $ 13.32  

Average price per Boe, excluding effects of derivatives

   $ 55.11      $ 41.38      $ 42.33      $ 30.32  

Average price per Boe, including effects of derivatives

   $ 53.29      $ 42.40      $ 44.16      $ 30.76  

Average unit costs per Boe:

           

Lease operating expenses

   $ 8.25      $ 12.13      $ 9.87      $ 10.52  

Workover, repair, and maintenance expenses

   $ 1.41      $ 1.52      $ 1.89      $ 1.98  

Transportation, gathering, and processing costs(2)

   $ 1.05        —          —          —    

General and administrative expenses

   $ 4.43      $ 3.20      $ 4.29      $ 5.43  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(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 $2.7 million for the three months ended March 31, 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 $66.00 per Bbl during the three months ended March 31, 2018. The International Energy Agency (“IEA”) forecasts steady or a 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 HH spot market price of natural gas was $3.14 per MMBtu. The NYMEX average HH spot price for natural gas decline 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 average HH spot price for natural gas reached a high above $3.60 per MMBtu during the three months ended March 31, 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 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 $51.34 per Bbl and HH $2.98 per MMBtu. On March 31, 2018 and December 31, 2017, the NYMEX WTI price for crude oil was $64.94 per Bbl and $60.42 per Bbl, respectively, and the NYMEX HH price of natural gas was $2.73 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 spot 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 three months ended March 31, 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. Additionally, our credit facility require us to maintain certain minimum hedging requirements with respect to our estimated proved developed producing oil and natural gas volumes. For a discussion of minimum hedge requirements under our credit facility, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Known Trends and Uncertainties—Commodity Derivatives.”

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 March 31, 2018, the fair value of our commodity derivative contracts was a net liability of $27.0 million. 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.

 

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Further, under the terms of our Revolving Credit Facility, the percentage of our total estimated production from 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

 

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resources from other strategic opportunities and from operational matters during this process. The integration 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

 

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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.”

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, discharge of greenhouse gases and limitations on hydraulic fracturing;

 

    pressure or irregularities in geological formations;

 

    loss of control or faculty or equipment malfunctions;

 

    shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

 

    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 and unauthorized discharges of brine, 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

 

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regulatory penalties, any of which could 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 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 December 31, 2017 reserve report 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

 

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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 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

 

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drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial 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.

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 December 31, 2017, approximately 27% of our total estimated proved reserves were classified as proved undeveloped. 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.

 

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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 March 31, 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 $227.7 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. In June 2018, as a result of semi-annual redetermination, the borrowing base was increased to $275.0 million. See “Management’s Discussion and Analysis of Financial Condition—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, 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

 

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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.

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.

 

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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 three months ended March 31, 2018 and the years ended December 31, 2017 and 2016, sales to Shell accounted for approximately 83%, 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 three months ended March 31, 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 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.

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

 

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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 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

 

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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.

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;

 

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    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 December 31, 2017, our top five fields constituted approximately 78% 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.

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

 

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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.

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

 

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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 plug 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 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,

 

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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.

The oil and natural gas business is subject to environmental hazards, such as oil spills, gas leaks and ruptures and discharges of petroleum products and hazardous substances and historical disposal activities. These environmental hazards could expose us to material liabilities, such as for property damages, personal injuries or other environmental harm, 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 was required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017. On December 21, 2017, the EPA, in response to an order from the D.C. Circuit, issued a notice of its intended designations, beginning a 120-day comment period. In April 2018, the EPA noted that it is completing nearly all remaining area designations. Certain areas of the country currently in compliance with the former ground-level ozone NAAQS standard may be reclassified as non-attainment and such reclassification may make it more difficult to construct new or modify existing infrastructure to control air pollution in newly designated non-attainment areas to be in compliance with NAAQS. 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. Additionally, our compliance with these laws may, from time to time, result in increased costs to our operations or decreased production, and may affect our costs of acquisitions.

In addition, existing, modified or new environmental laws may, in the future, cause a decrease 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.

 

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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 Bureau of Safety and Environmental Enforcement (“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 required incremental financial assurance or bonding for sole liability properties, 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 March 31, 2018, our asset retirement obligations totaled $157.5 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 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 in October 2017, the EPA proposed to repeal the CPP and is expected to propose a revised rule in the future. 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.

 

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In June 2016, the EPA published new source performance 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 onshore equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, 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.

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, 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, 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

 

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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.

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

 

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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.

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;

 

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    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 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.

In connection with the interim review of our consolidated financial statements as of and for the six months ended June 30, 2017 and the audit of our financial statements as of and for the year ended December 31, 2017, we identified 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.

Management determined that the errors identified with respect to these periods resulted from material weaknesses in our internal controls primarily over the preparation, validation and reviews of the DD&A expense calculations and full cost ceiling tests and the accounting for our Series A preferred stock issued on December 31, 2016. Further, it was determined that we did not have a sufficient number of trained resources for key financial reporting processes and internal controls. We have corrected these errors in our financial statements

 

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for the years ended December 31, 2017 and 2016 that are included in this prospectus. In addition, we have 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.

Currently, we are a private company and have not been required to file reports with the SEC. 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 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

 

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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. Despite our efforts to mitigate “spoof” and “phishing” emails through education, “spoof” and “phishing” activities remain a serious problem that may damage our information technology infrastructure. 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.

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.

 

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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 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

 

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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 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. 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.

 

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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 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 the 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

 

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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 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 challenged 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.

Immediately 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

 

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sufficient to cover the taxes on our and the other LLC Units holders’ respective allocable shares of the taxable 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 common stock at an attractive price, or at all. The price for our Class A common stock in this offering will be

 

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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. 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;

 

    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;

 

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    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 stockholders’ agreement with                 . The stockholders’ agreement provides                  with the right to designate a certain number of nominees to our board of directors so long as                  and its affiliates collectively beneficially own at least         % of the outstanding shares of our Class A common stock. See “Certain Relationships and Related Party Transactions—Stockholders’ 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 provides 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.

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, if any, 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 pay any 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) 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, and investors will be relying on the judgment of our management regarding the application of the proceeds. Pending their use, we may invest the 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 March 31, 2018:

 

    on an actual basis;

 

    on an as adjusted basis to reflect 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 and to give further effect to 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.

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 months ended March 31, 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 March 31, 2018  
(In thousands, except number of shares and par value)    Actual     As Adjusted  

Cash and cash equivalents(1)

   $ 55,305    
  

 

 

   

 

 

 

Long-term debt:

    

Revolving Credit Facility(2)

     —      

11.00% Senior notes due 2023(3)

   $ 328,250    
  

 

 

   

 

 

 

Total long-term debt

   $ 328,250    
  

 

 

   

 

 

 

Equity(4):

    

Accumulated deficit

   $ (79,240  

Stockholders’ equity:

    

Series A convertible perpetual preferred stock, par value $0.001; 25,000,000 shares authorized and 9,637,312 shares issued and outstanding as of March 31, 2018 actual; no shares authorized, issued or outstanding, as adjusted

   $ 10    

Class A common stock, par value $0.001; 200,000,000 shares authorized and 16,139,718 shares issued and outstanding as of March 31, 2018 actual; shares authorized, issued and outstanding, as adjusted

   $ 16    

Class B common stock, par value $0.001; 50,000,000 shares authorized and 3,333,333 shares issued and outstanding as of March 31, 2018 actual; shares authorized, issued and outstanding, as adjusted

   $ 3    

Additional paid-in capital

   $ 284,802    
  

 

 

   

 

 

 

Total stockholders’ equity

   $ 205,591    
  

 

 

   

 

 

 

Non-controlling interest

   $ 27,338    
  

 

 

   

 

 

 

Total equity

   $ 232,929    
  

 

 

   

 

 

 

Total capitalization

   $ 561,179    
  

 

 

   

 

 

 

 

(1) Does not include current portion of restricted cash as of March 31, 2018 of approximately $6.8 million reserved as cash collateral for certain bonding requirements. Restricted cash includes amounts held in escrow for plug and abandonment obligations.
(2) At March 31, 2018, we had no outstanding borrowings under our Revolving Credit Facility and availability of $227.7 million (after giving effect to $3.6 million of outstanding letters of credit). In June 2018, as a result of a semi-annual redetermination, we increased our borrowing base to $275.0 million.

 

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(3) Due to the fair value option election, the 2023 Notes are presented at their fair value as of March 31, 2018.
(4) As of March 31, 2018, we had Series A Warrants and Series B Warrants outstanding, each of which was exercisable to purchase 0.07282 share of Class A common stock. 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.

 

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DIVIDEND POLICY

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 and we may reduce or discontinue entirely the payment of any such dividends at any time. 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. 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.

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, if any, 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.

Our pro forma net tangible book value as of March 31, 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 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 March 31, 2018 would have been approximately $         or $         per share of Class A common stock. 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

  

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

  
  

 

 

 

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.

The following table sets forth, on a pro forma basis, as of March 31, 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,

 

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    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 of outstanding stock options after of March 31, 2018. As of March 31, 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 March 31, 2018 and the summary consolidated statement of operations data, statement of cash flows data and other financial data for each of the three months ended March 31, 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)

   Three months ended
March 31,
    Year ended
December 31,
 
   2018     2017     2017     2016  

Statement of operations

        

Total revenues(1)

   $ 147,347     $ 114,879     $ 434,411     $ 203,319  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses(1):

        

Lease operating expenses

     21,473       32,718       97,560       67,918  

Workover, repair, and maintenance expenses

     3,671       4,096       18,642       12,754  

Transportation, gathering, and processing costs(2)

     2,735       —         —         —    

Depreciation, depletion, and amortization

     47,409       47,964       170,372       104,584  

General and administrative expenses

     11,534       8,654       42,397       35,078  

Accretion of asset retirement obligations

     8,438       7,485       31,392       21,669  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

   $ 95,260     $ 100,917     $ 360,363     $ 242,003  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ 52,087     $ 13,962     $ 74,048     $ (38,684
  

 

 

   

 

 

   

 

 

   

 

 

 

Other (expense) income:

        

Interest expense

     (24,116     (15,041     (60,307     (31,545

(Loss) gain on derivatives, net

     (13,752     22,814       5,020       (9,153

Interest income

     1,172       1,040       4,370       3,916  

Loss on extinguishment of long-term debt

     (4,012     —         —         —    

Loss on fair value of 11.00% Senior notes due 2023

     (3,250     —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other (expense) income

   $ (43,958   $ 8,813     $ (50,917   $ (36,782
  

 

 

   

 

 

   

 

 

   

 

 

 

Income tax expense

     416       —         14,095       —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 7,713     $ 22,775     $ 9,036     $ (75,466
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to non-controlling interest

   $ 783     $ 3,716     $ 2,581     $ (14,371
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to EnVen Energy Corporation

   $ 6,930     $ 19,059     $ 6,455     $ (61,095
  

 

 

   

 

 

   

 

 

   

 

 

 

Series A preferred stock dividends

     (6,535     (4,392     (21,590     (49
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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(In thousands, except for the number of shares outstanding
and per share amounts)

   Three months ended
March 31,
    Year ended
December 31,
 
   2018     2017     2017     2016  

Net income (loss) attributable to EnVen Energy Corporation common stockholders

   $ 395     $ 14,667     $ (15,135   $ (61,144

Net income (loss) per common share—basic

   $ 0.02     $ 0.89     $ (0.95   $ (4.13

Net income (loss) per common share—diluted

   $ 0.02     $ 0.68     $ (0.95   $ (4.13

Weighted average common shares outstanding—basic

     16,132,490       15,861,704       15,912,950       14,795,005  

Weighted average common shares outstanding—diluted

     16,942,961       27,708,099       15,912,950       14,795,005  

Statement of cash flows data

        

Net cash provided by operating activities

   $ 76,161     $ 38,775     $ 191,482     $ 26,954  

Net cash used in investing activities

   $ (34,089   $ (13,459   $ (84,759   $ (243,631

Net cash (used in) provided by financing activities

   $ (13,645   $ (34,154   $ (99,406   $ 242,633  

 

(In thousands)    As of
March 31,
2018
     As of
December 31,
2017
 

Balance sheet data

     

Cash and cash equivalents(3)

     55,305        28,848  

Accounts receivable

     65,000        68,305  

Other current assets

     25,702        28,373  
  

 

 

    

 

 

 

Total current assets

   $ 146,007      $ 125,526  
  

 

 

    

 

 

 

Property and equipment, net

     676,584        691,490  

Other non-current assets

     129,976        126,025  
  

 

 

    

 

 

 

Total assets

   $ 952,567      $ 943,041  
  

 

 

    

 

 

 

Current liabilities

     124,447        140,375  

Other non-current liabilities

     595,191        552,281  
  

 

 

    

 

 

 

Total liabilities

   $ 719,638      $ 692,656  
  

 

 

    

 

 

 

Total equity

     232,929        250,385  
  

 

 

    

 

 

 

Total liabilities and equity

   $ 952,567      $ 943,041  
  

 

 

    

 

 

 

 

(1) The total revenues and total operating expenses for the three months ended March 31, 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 $2.7 million of transportation, gathering, and processing costs for the three months ended March 31, 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) Does not include current portion of restricted cash of approximately $6.8 million and $9.5 million as of March 31, 2018 and 2017, respectively, and approximately $6.8 million and $9.5 million as of December 31, 2017 and 2016, respectively, reserved as cash collateral for certain bonding requirements and amounts held in escrow for plug 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 developing and acquiring producing deepwater assets that we believe have untapped development opportunities and will provide strong cash flow and lower-risk development with significant exploration potential. This strategy allows us to benefit from the favorable geologic and economic characteristics of the deepwater U.S. Gulf of Mexico.

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 the current commodity price environment has motivated large operators 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.

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 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.

 

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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 $66.14 per Bbl and a low of $59.19 per Bbl for the three months ended March 31, 2018 compared to a high of $54.45 per Bbl and a low of $47.34 per Bbl for the three months ended March 31, 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 three months ended March 31, 2018 compared to a high of $3.42 per MMBtu and a low of $2.56 per MMBtu for the three months ended March 31, 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 (“Class A Common Stock”) of Energy Ventures GoM Holdings, LLC, one warrant to purchase 0.07282 shares of Class A Common Stock and one warrant to purchase 0.07282 shares of Class A Common Stock, 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.”

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

 

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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 (the “Shell Series A Preferred Stock Offering”).

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 three months ended March 31, 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, $2.7 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 three months ended March 31, 2018. We have elected to adopt ASC 606 using the modified retrospective approach, and as such, prior period amounts for the three months ended March 31, 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 discussion regarding the impact of adopting ASC 606 on our first quarter 2018 results.

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 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.

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

 

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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 three months ended March 31, 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 three months ended March 31, 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 deduct of $0.78 per Bbl and $0.50 per Bbl, respectively, for the three months ended March 31, 2018 compared to an approximate deduct of $2.46 per Bbl and $2.13 per Bbl, respectively, for the three months ended March 31, 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 three months ended March 31, 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 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.

 

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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:

 

     Three months ended
March 31,
    Year ended
December 31,
 
       2018         2017(1)       2017(1)     2016(1)  

Oil (per Bbl):

        

NYMEX WTI Average

   $ 62.89     $ 51.78     $ 50.85     $ 43.47  

Average realized price (excluding effects of derivatives)(2)

   $ 63.01     $ 47.31     $ 48.66     $ 37.18  

Average realized price differential to benchmark(3)

   $ 0.12     $ (4.47   $ (2.19   $ (6.29

Percentage of average realized price to benchmark(3)

     100.2     91.4     95.7     85.5

Average realized price (including effects of derivatives)(2)(4)

   $ 60.54     $ 48.34     $ 50.67     $ 37.68  

Natural gas:

        

NYMEX HH Average ($/MMBtu)

   $ 2.85     $ 3.06     $ 3.02     $ 2.55  

Average realized price (excluding effects of derivatives) ($/Mcf)

   $ 3.67     $ 3.11     $ 2.93     $ 2.12  

Average realized price differential to benchmark ($/Mcf)(3)(5)

   $ 0.71     $ (0.06   $ (0.20   $ (0.52

Percentage of average realized price to benchmark(3)(5)

     124.2     98.1     93.6     80.3

Average realized price (including effects of derivatives) ($/Mcf)(4)

   $ 3.84     $ 3.29     $ 3.15     $ 2.18  

NGLs (per Bbl):

        

Average realized price

   $ 30.69     $ 19.88     $ 18.21     $ 13.32  

 

(1) The average realized prices (excluding and including effects of derivatives) for the three months ended March 31, 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 three months ended March 31, 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 three months ended March 31, 2018 was $63.01 per Bbl compared to the NYMEX WTI average price of $62.89 per Bbl. Our average realized oil price (excluding effects of derivatives) for the three months ended March 31, 2017 was $47.31 per Bbl compared to the NYMEX WTI average price of $51.78 per Bbl. The 33.2% increase in our average realized oil price was largely due to a 21.5% increase in the NYMEX WTI average price and a more favorable realized price differential to benchmark which increased to $0.12 per Bbl for the three months ended March 31, 2018 primarily due to more favorable 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 three months ended March 31, 2018 were more favorable by $1.68 per Bbl and $1.63 per Bbl, respectively, compared to the same period of 2017. Additionally, our average realized oil price increased by $0.39 per Bbl during the three months ended March 31, 2018 due to the adoption of ASC 606, which resulted in $0.8 million of transportation and gathering costs that are now presented as a component of operating expenses and not as a reduction to oil revenue.

 

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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 three months ended March 31, 2018 was $3.67 per Mcf compared to the NYMEX HH average price of $2.85 per MMBtu. Our average realized natural gas price (excluding effects of derivatives) for the three months ended March 31, 2017 was $3.11 per Mcf compared to the NYMEX HH average price of $3.06 per MMBtu. The 18.0% increase in our average realized natural gas price was largely due to a more favorable realized price differential to benchmark of $0.71 per Mcf for the three months ended March 31, 2018. Additionally, our average realized natural gas price increased by $0.43 per Mcf during the three months ended March 31, 2018 due to the adoption of ASC 606, which resulted in $1.1 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 a 6.9% 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 three months ended March 31, 2018 was $30.69 per Bbl compared to $19.88 per Bbl for the three months ended March 31, 2017. The 54.4% 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 $0.5 million which are now presented as a component of operating expenses and not as a reduction to NGL revenue due to the adoption of ASC 606. Additionally, the increase in our average realized NGL price was also driven by an 8.6% increase in the Mount Belvieu ethane monthly settle average for the three months ended March 31, 2018 compared to the same period in 2017.

Our average realized NGL price for the year ended December 31, 2017 was $18.21 per Bbl compared to $13.32 per Bbl for the year ended December 31, 2016. The 36.7% increase in our average realized NGL price was primarily due to more favorable ethane, propane, and butane realized prices for the year ended

 

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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 producing developed 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.”

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 what we have done historically. 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 twelve months and 50% of our estimated production from our proved developed producing oil and natural gas properties for 13-18 months on a Boe basis, from the minimum hedging test date of March 15th and September 15th of each year.

We currently do not have any hedges in place for the first quarter of 2020 or beyond that time.

 

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All of our oil and natural gas derivative contracts are indexed to the NYMEX WTI and NYMEX HH, respectively, and as of March 31, 2018, our outstanding commodity derivative instrument positions were as follows:

 

     2018      2019  

Oil Purchased Puts:

     

Notional volume (Bbl)

     625,815        678,000  

Weighted average price ($/Bbl)

   $ 50.00      $ 49.00  

Oil Swaps:

     

Notional volume (Bbl)

     1,078,390        763,563  

Weighted average price ($/Bbl)

   $ 53.16      $ 50.70  

Oil Collars:

     

Notional volume (Bbl)

     2,296,227        —    

Weighted average floor price ($/Bbl)

   $ 48.98      $ —    

Weighted average ceiling price ($/Bbl)

   $ 63.99      $ —    

Oil Three-way Collars:

     

Notional volume (Bbl)

     549,661        —    

Weighted average sub-floor price ($/Bbl)

   $ 40.00      $ —    

Weighted average floor price ($/Bbl)

   $ 50.00      $ —    

Weighted average ceiling price ($/Bbl)

   $ 65.06      $ —    

Oil Put Spreads:

     

Notional volume (Bbl)

     —          666,807  

Weighted average sub-floor price ($/Bbl)

   $ —        $ 42.02  

Weighted average floor price ($/Bbl)

   $ —        $ 52.02  

Natural Gas Purchased Puts:

     

Notional volume (MMBtu)

     3,227,214        906,861  

Weighted average price ($/MMBtu)

   $ 2.75      $ 2.75  

Natural Gas Swaps:

     

Notional volume (MMBtu)

     1,388,861        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  

Oil and Natural Gas Properties Full Cost Ceiling Test

Our estimated proved oil, natural gas, and NGL reserve quantities and future revenues depend largely on oil, natural gas, and NGL prices, which have historically been very volatile. During the three months ended March 31, 2018 and 2017, commodity prices have increased and we did not recognize any impairments of oil and natural gas properties during these periods. 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.

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.

 

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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 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 three months ended March 31, 2018, we recognized income tax expense of $0.4 million, resulting in an effective tax rate of 5.1%. 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%. Prior to the year ended December 31, 2017, we have not recognized any income tax expense or benefit nor have we made any significant federal income tax payments.

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 three months ended March 31, 2018 included elsewhere in this prospectus.

Additionally, we generate revenue from third-party production handling arrangements, 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 arrangements 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

 

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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. 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

 

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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.

Results of Operations

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

 

     Three months ended
March 31,
    Year ended
December 31,
 
     2018     2017     2017     2016  
     (In thousands, except prices)  

Selected financial data:

        

Total revenues(1)

   $ 147,347     $ 114,879     $ 434,411     $ 203,319  

Total operating expenses(1)

     95,260       100,917       360,363       242,003  

Operating income

     52,087       13,962       74,048       (38,684

Total other (expense) income

     (43,958     8,813       (50,917     (36,782

Income before income taxes

     8,129       22,775       23,131       (75,466

Income tax expense

     416       —         14,095       —    

Net income (loss)

     7,713       22,775       9,036       (75,466

Net income (loss) attributable to non-controlling interest

     783       3,716       2,581       (14,371

Net income (loss) attributable to EnVen Energy Corporation

     6,930       19,059       6,455       (61,095

Series A preferred stock dividends

     (6,535     (4,392     (21,590     (49
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to EnVen Energy Corporation common stockholders

   $ 395     $ 14,667     $ (15,135   $ (61,144
  

 

 

   

 

 

   

 

 

   

 

 

 

Production:

        

Oil (MBbls)

     2,085       2,137       7,865       4,636  

Natural gas (MMcf)

     2,647       3,001       10,316       9,243  

NGLs (MGals)

     3,245       2,565       12,649       11,709  

Total production (MBoe)

     2,603       2,698       9,885       6,455  

Average sales prices:(2)

        

Oil (per Bbl)

   $ 63.01     $ 47.31     $ 48.66     $ 37.18  

Natural gas (per Mcf)

   $ 3.67     $ 3.11     $ 2.93     $ 2.12  

NGLs (per Bbl)

   $ 30.69     $ 19.88     $ 18.21     $ 13.32  

Average price (per Boe)

   $ 55.11     $ 41.38     $ 42.33     $ 30.32  

 

(1) The total revenues and total operating expenses for the three months ended March 31, 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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Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Production

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

 

     Three months ended March 31,              
     2018     2017              
     Volume      % of Total     Volume      % of Total     Change     % Change  

Production:

              

Oil (MBbls)

     2,085        80.1     2,137        79.2     (52     (2.4 )% 

Natural gas (MMcf)

     2,647        16.9     3,001        18.5     (354     (11.8 )% 

NGLs (MGals)

     3,245        3.0     2,565        2.3     680       26.5
     

 

 

      

 

 

     

Total production (MBoe)

     2,603        100.0     2,698        100.0     (95     (3.5 )% 

Average daily production:

              

Oil (MBbls/d)

     23.2        80.1     23.7        79.2     (0.5  

Natural gas (MMcf/d)

     29.4        16.9     33.3        18.5     (3.9  

NGLs (MGals/d)

     36.1        3.0     28.5        2.3     7.6    
     

 

 

      

 

 

     

Total production (MBoe/d)

     28.9        100.0     30.0        100.0     (1.1  

For the three months ended March 31, 2018, oil production decreased by 52 MBbls, or 2.4%, natural gas production decreased by 354 MMcf, or 11.8%, NGL production increased by 680 MGals, or 26.5%, and total production decreased by 95 MBoe, or 3.5%, compared to the three months ended March 31, 2017. During the three months ended March 31, 2018, production volumes from our Brutus, Glider, and Lobster fields increased as a result of our multi-project capital programs at those fields and NGL production volumes recognized from our Cognac field increased. These increases were primarily offset by the natural production decline associated with our oil and natural gas properties as well as a brief, non-recurring shut-in of the natural gas pipeline servicing our Brutus and Glider fields, which was resolved in the first quarter of 2018.

Revenue

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

 

     Three months ended March 31,  
     2018      2017(1)      Change     % Change  
     (In thousands, except prices and percentages)  

Oil revenue

   $ 131,371      $ 101,093      $ 30,278       30.0

Natural gas revenue

     9,710        9,346        364       3.9

NGL revenue

     2,371        1,214        1,157       95.3

Production handling and other income

     3,895        3,226        669       20.7
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

   $ 147,347      $ 114,879      $ 32,468       28.3
  

 

 

    

 

 

    

 

 

   

 

 

 

Production:

          

Oil (MBbls)

     2,085        2,137        (52     (2.4 )% 

Natural gas (MMcf)

     2,647        3,001        (354     (11.8 )% 

NGLs (MGals)

     3,245        2,565        680       26.5

Total production (MBoe)

     2,603        2,698        (95     (3.5 )% 

Average sales prices:(2)

          

Oil (per Bbl)

   $ 63.01      $ 47.31      $ 15.70       33.2

Natural gas (per Mcf)

   $ 3.67      $ 3.11      $ 0.56       18.0

NGLs (per Bbl)

   $ 30.69      $ 19.88      $ 10.81       54.4

Average price (per Boe)

   $ 55.11      $ 41.38      $ 13.73       33.2

 

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(1) The oil, natural gas, and NGL revenues for the three months ended March 31, 2017 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) Excluding effects of derivatives.

Oil revenue. For the three months ended March 31, 2018, oil revenues were $131.4 million compared to $101.1 million for the three months ended March 31, 2017. The increase of 30.0% was primarily driven by a 33.2% increase in our average realized oil price primarily due to higher commodity prices during the three months ended March 31, 2018 compared to the same period in 2017. Additionally, as a result of the adoption of ASC 606, our oil revenue for the three months ended March 31, 2018 excluded certain transportation and gathering costs for our oil contracts resulting in an increase of $0.8 million in total oil revenue and an increase of $0.39 per Bbl in our average realized oil price. Additionally, as a result of the capital programs at our Brutus, Glider and Lobster fields, our oil production volumes from those fields increased for the three months ended March 31, 2018 compared to the same period of 2017. These increases were offset by a brief, non-recurring, unanticipated shut-in of the natural gas pipeline servicing our Brutus and Glider fields, which was resolved in the first quarter of 2018.

Natural gas revenue. For the three months ended March 31, 2018, natural gas revenues were $9.7 million compared to $9.3 million for the three months ended March 31, 2017. The increase of 3.9% was primarily driven by the adoption ASC 606, which resulted in an increase of $1.1 million primarily due to the exclusion of certain transportation, gathering, and processing costs for our natural gas contracts from our natural gas revenues for the three months ended March 31, 2018. The increase in total natural gas revenue resulted in a $0.43 increase in our average realized natural gas price. This increase was offset by an 11.8% decrease in natural gas production volumes primarily driven by a brief, non-recurring, unanticipated shut-in of the natural gas pipeline servicing our Brutus and Glider fields which was resolved in the quarter 2018. This decrease was partially offset with an increase in natural gas production volumes from our Brutus, Glider, and Lobster fields driven by our capital programs at those fields.

NGL revenue. For the three months ended March 31, 2018, NGL revenues were $2.4 million compared to $1.2 million for the three months ended March 31, 2017. The increase of 95.3% was primarily driven by a 54.4% increase in our average realized NGL price partially due to higher commodity prices during the three months ended March 31, 2018 compared to the same period of 2017. Additionally, as a result of the adoption of ASC 606, our NGL revenue for the three months ended March 31, 2018 excluded certain transportation, gathering, and processing costs for our NGL contracts resulted in an increase of $0.5 million in total NGL revenue and an increase of $6.92 in our average realized NGL price. Our NGL production volumes increased by 26.5% for the three months ended March 31, 2018 primarily driven by an increase in recognized NGL volumes from our Cognac field and overall increased production volumes from our Brutus, Glider and Lobster fields resulting from our capital programs at those fields.

Production handling and other income. For the three months ended March 31, 2018, production handling and other income was $3.9 million compared to $3.2 million for the three months ended March 31, 2017. The adoption of ASC 606 resulted in an increase of $0.2 million. The remainder of the increase was driven by an increase in third-party volumes processed under our production handling arrangements.

 

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Operating Expenses

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

 

     Three months ended March 31,  
     2018      2017      Change     % Change  
     (In thousands, except prices and percentages)  

Lease operating expenses

   $ 21,473      $ 32,718      $ (11,245     (34.4 )% 

Workover, repair, and maintenance expenses

     3,671        4,096        (425     (10.4 )% 

Transportation, gathering, and processing costs

     2,735        —          2,735       100.0

Depreciation, depletion, and amortization

     47,409        47,964        (555     (1.2 )% 

General and administrative expenses

     11,534        8,654        2,880       33.3

Accretion of asset retirement obligations

     8,438        7,485        953       12.7
  

 

 

    

 

 

    

 

 

   

 

 

 

Total operating expenses

   $ 95,260      $ 100,917      $ (5,657     (5.6 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Operating expenses per Boe:

          

Lease operating expenses

   $ 8.25      $ 12.13      $ (3.88     (32.0 )% 

Workover, repair, and maintenance expenses

   $ 1.41      $ 1.52      $ (0.11     (7.2 )% 

Transportation, gathering, and processing costs

   $ 1.05      $ —        $ 1.05       100.0

Depreciation, depletion, and amortization

   $ 18.22      $ 17.78      $ 0.44       2.5

General and administrative expenses

   $ 4.43      $ 3.20      $ 1.23       38.4

Accretion of asset retirement obligations

   $ 3.24      $ 2.77      $ 0.47       17.0
  

 

 

    

 

 

    

 

 

   

 

 

 

Total operating expenses per Boe

   $ 36.60      $ 37.40      $ (0.80     (2.1 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Lease operating expenses. For the three months ended March 31, 2018, LOE was $21.5 million compared to $32.7 million for the three months ended March 31, 2017. LOE per Boe decreased from $12.13 per Boe for the three months ended March 31, 2017 to $8.25 per Boe for the three months ended March 31, 2018. The decrease of 34.4% in total LOE and 32.0% in LOE per Boe was primarily driven by realized operating cost savings related to the properties acquired from Shell resulting from increased operating efficiencies.

Workover, repair, and maintenance expenses. For the three months ended March 31, 2018, workover, repair, and maintenance expenses remained relatively flat compared to the same period in 2017.

Transportation, gathering, and processing costs. As a result of the adoption of ASC 606, transportation, gathering, and processing costs were $2.7 million for the three months ended March 31, 2018. Prior to the adoption 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 “—Factors Affecting Comparability—Revenue Recognition—Adoption of ASC 606” for further discussion of the adoption of ASC 606.

Depreciation, depletion, and amortization. For the three months ended March 31, 2018, total DD&A was $47.4 million compared to $48.0 million for the three months ended March 31, 2017. The slight decrease of $0.6 million in total DD&A was primarily attributable to a decrease in the balance of oil and natural gas properties subject to DD&A partially offset by an increase in the percentage of our reserves produced during the three months ended March 31, 2018 compared to the same period in 2017. DD&A per Boe increased slightly by 2.5%, from $17.78 per Boe for the three months ended March 31, 2017 to $18.22 per Boe for the three months ended March 31, 2018.

General and administrative expenses. For the three months ended March 31, 2018, G&A expenses were $11.5 million compared to $8.7 million for the three months ended March 31, 2017. G&A expenses per Boe increased from $3.20 per Boe for the three months ended March 31, 2017 to $4.43 per Boe for the three months ended March 31, 2018. The increase of 33.3% in total G&A and 38.4% in G&A expenses per Boe was primarily due to a $1.0 million increase in accounting and other professional fees, a $1.0 million increase in compensation

 

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expense and general office expenses resulting from increased employee headcount, and a $1.0 million increase in non-cash stock-based compensation expense due to an increase in outstanding Restricted Stock and stock options.

Accretion of asset retirement obligations. For the three months ended March 31, 2018, accretion of asset retirement obligations increased slightly to $8.4 million compared to $7.5 million for the three months ended March 31, 2017. The increase of 12.7% in total accretion expense is a result of an overall net increase in the asset retirement obligations balance subject to accretion expense. Accretion of asset retirement obligations per Boe increased from $2.77 per Boe for the three months ended March 31, 2017 to $3.24 per Boe for the three months ended March 31, 2018 due to slightly lower production volumes and overall higher accretion expense during the three months ended March 31, 2018 compared to the same period in 2017.

Other Expenses

Interest expense. For the three months ended March 31, 2018, interest expense was $24.1 million compared to $15.0 million for the three months ended March 31, 2017. The increase of 60.3% 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 $4.3 million in interest per the 2023 Notes contractual rate. These increases were offset with a decrease of $5.5 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 three months ended March 31, 2018 compared to the same period in 2017 also as a result of the 2018 Refinancing Transactions.

Loss on extinguishment of long-term debt. During the three months ended March 31, 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 three months ended March 31, 2018, we recognized a loss on fair value of our 2023 Notes of $3.3 million.

(Loss) gain on derivatives, net. For the three months ended March 31, 2018, (loss) gain on derivatives, net was a loss of $(13.8) million compared to a gain of $22.8 million for the three months ended March 31, 2017. The decrease was primarily due to a $29.1 million decrease in the fair value of outstanding derivative contracts as of March 31, 2018 compared to the same period in 2017. Additionally, derivative cash settlements decreased $7.4 million during the three months ended March 31, 2018 compared to the same period in 2017.

Income tax expense. For the three months ended March 31, 2018, we recognized income tax expense of $0.4 million, resulting in an effective tax rate of 5.1%. Our effective tax rate is primarily driven by the federal statutory rate and allocations of income from the underlying partnership to us. The overall increase in effective tax rate for the three months ended March 31, 2018 is due primarily to increased income allocations from the underlying partnership to us, partially offset by the decrease in the federal statutory rate from 35% to 21% due to the Tax Cuts and Jobs Act.

 

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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 (MGals)

     12,649        3.0     11,709        4.3     940        8.0
     

 

 

      

 

 

      

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 (MGals/d)

     34.7        3.0     32.1        4.3     2.6     
     

 

 

      

 

 

      

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 940 MGals, or 8.0%, 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 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 (MGals)

     12,649        11,709        940        8.0

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)

   $ 18.21      $ 13.32      $ 4.89        36.7

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 36.7% 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 arrangements 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 prices 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 March 31, 2018, we had $227.7 million of availability under our Revolving Credit Facility (after giving effect to $3.6 million of outstanding letters of credit), which remains undrawn, and $55.3 million in cash and cash equivalents on hand. In June 2018, as a result of a semi-annual redetermination, we increased our borrowing base to $275.0 million. 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 total 2018 and 2019 capital program of $450 million to $500 million, excluding nominal annual P&A of $20 million to $30 million, is primarily focused on the continued development of our operated Brutus, Glider, Lobster, and Cognac fields. These four fields account for approximately 66% of the total capital program over that period. In addition, approximately 30% of our capital budget is allocated to either properties we operate or cost centers we control, with the remaining 4% allocated to non-operated drill wells and recompletions. Based on current commodity prices, we expect to fully fund this capital program with cash on hand and internally generated cash flows.

During the three months ended March 31, 2018, net cash provided by operating activities was $76.2 million and our capital expenditures on an accrual basis, excluding P&A expenditures, were approximately $31.6 million, which included capital expenditures of approximately $17.3 million related to capital programs in the Brutus and Glider fields and approximately $10.3 million related to the capital program at the Lobster field.

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 December 31, 2017 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 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.

 

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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:

 

     Three months ended March 31,     Year ended December 31,  
         2018             2017         2017     2016  
           (In thousands)              

Net cash provided by operating activities

   $ 76,161     $ 38,775     $ 191,482     $ 26,954  

Net cash used in investing activities

     (34,089     (13,459     (84,759     (243,631

Net cash (used in) provided by financing activities

   $ (13,645   $ (34,154   $ (99,406   $ 242,633  

Net cash provided by operating activities. Net cash provided by operating activities totaled $76.2 million and $38.8 million during the three months ended March 31, 2018 and 2017, respectively. The increase of $37.4 million during the three months ended March 31, 2018 compared to the three months ended March 31, 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 and workover, repair, and maintenance expenses 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 in net income were offset with decrease in net (loss) gain on derivatives, net of $36.6 million primarily due to an increase in the future commodity price outlook during the three months ended March 31, 2018 compared to a decrease in the commodity price outlook during the three months ended March 31, 2017.

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

 

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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 $34.1 million and $13.5 million during the three months ended March 31, 2018 and 2017, respectively. The increase of $20.6 million during the three months ended March 31, 2018 compared to the three months ended March 31, 2017 was almost entirely attributable to an increase in capital expenditures for property and equipment of $20.4 million during the three months ended March 31, 2018. The majority of our capital expenditures for the three months ended March 31, 2018 were related to drilling and completion activities at the Brutus, Glider, and Lobster fields.

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 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, Glider, and Lobster fields.

Net cash (used in) provided by financing activities. Net cash used in financing activities totaled $13.6 million and $34.2 million during the three months ended March 31, 2018 and 2017, respectively. The net cash used in financing activities for the three months ended March 31, 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 three months ended March 31, 2017 was attributable to net paydowns of our outstanding borrowings under our Revolving Credit Facility and Second Lien Term Loan of $32.8 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 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.

 

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Working Capital

Our working capital totaled $21.6 million and $(14.8) million as of March 31, 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 March 31, 2018, our cash balance was $55.3 million. Due to the amounts we accrue related to our drilling program, we could, and have had in the past, incur working capital deficits in the future. 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 March 31, 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 March 31, 2018 and December 31, 2017. During the three months ended March 31, 2018 and 2017, we recognized interest expense of $0.8 million and $2.2 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

   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

   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

   The last day of each fiscal quarter, beginning with the fiscal quarter ending December 31, 2017      2.50:1.00  

The Revolving Credit Facility agreement defines EBITDAX, for any period, as our net income for the period plus the following expenses or charges to the extent deducted from our net income for the period: interest, income taxes, DD&A (including the amortization of deferred financing costs), exploration expenses, accretion of ARO, and other similar non-cash charges, minus 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. The pro forma adjustments would also add any non-recurring, one-time cash, or non-cash charges or expenses associated with the acquisition or disposition back 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 March 31, 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.

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

 

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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 March 31, 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 three months ended March 31, 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 three months ended March 31, 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 P&A expenditures to be between $20 million and $30 million, 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. See “—Known Trends and Uncertainties—Financial Assurances for Decommission Obligations” for further discussion of these requirements.

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 December 31, 2017 and 2016, we provided surety companies with cash collateral of $41.0 million and $39.6 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 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

 

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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 March 31, 2018 and December 31, 2017, the escrow balance was $7.4 million and $5.5 million, respectively, which is recorded in restricted cash on the consolidated financial statements 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 $49.2 million and $48.1 million, as of March 31, 2018 and December 31, 2017, respectively.

Contractual Obligations

As of March 31, 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)

     285,225        23,651        60,163        107,645        93,766  

Operating leases(3)

     2,003        1,346        657        —          —    

Other long-term obligations(4)

     5,059        5,033        26        —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 617,287      $ 30,030      $ 60,846      $ 432,645      $ 93,766  

 

(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) 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.
(4) As of March 31, 2018, other long-term obligations primarily includes $5.0 million of installment payments due for equipment purchased. These future obligations do not include any interest expense or other fees.

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 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.

 

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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.

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

 

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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 three months ended March 31, 2018 and 2017 was $47.2 million and $47.3 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 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, we recognize an impairment equal to the excess of the net capitalized costs over the ceiling limitation. The significant inputs used in estimated future net cash flows from proved oil and natural gas reserves include estimates relating to future oil and natural gas production, future commodity prices, future operating costs, and a credit-risk adjusted discount rate. These significant inputs are based on unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. No impairment was recognized for the three months ended March 31, 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 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

 

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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.

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

 

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Index to Financial Statements

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