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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

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

For the fiscal year ended December 31, 2017

or

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

For the transition period from                  to

Commission file number: 000‑1404973

Energy XXI Gulf Coast, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware

    

20‑4278595

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

 

 

1021 Main, Suite 2626
Houston, Texas

 

77002

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code: (713)‑351‑3000

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

 

Title of each class

    

Name of each exchange on which registered under Section 12(b) of the Act

Common Stock, par value $0.01 per share

 

The Nasdaq Global Select Market

 

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒    No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes   ☒    No  ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. ☒

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

 

 

 

 

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

 

Emerging growth company

(Do not check if a smaller reporting company)

 

 

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

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $451,144,204 based on the closing sale price of $18.57 per share as reported on The NASDAQ Global Select Market on June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes   ☒    No  ☐

The number of shares of the registrant’s common stock outstanding on March 2, 2018 was 33,268,478.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2018 Annual Meeting of Stockholders, which will be filed within 120 days of December 31, 2017, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 

 

 

 


 

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Page

 

 

 

 

 

GLOSSARY OF TERMS 

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS 

 

1

 

 

 

 

 

 

 

 

 

 

PART I 

 

 

 

 

 

 

 

Item 1 

 

Business

 

3

Item 1A 

 

Risk Factors

 

22

Item 1B 

 

Unresolved Staff Comments

 

44

Item 2 

 

Properties

 

44

Item 3 

 

Legal Proceedings

 

44

Item 4 

 

Mine Safety Disclosures

 

44

 

 

 

 

 

PART II 

 

 

 

 

 

 

 

Item 5 

 

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

 

45

Item 6 

 

Selected Financial Data

 

46

Item 7 

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

50

Item 7A 

 

Quantitative and Qualitative Disclosures About Market Risk

 

79

Item 8 

 

Financial Statements and Supplementary Data

 

82

Item 9 

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 

157

Item 9A 

 

Controls and Procedures

 

158

Item 9B 

 

Other Information

 

159

 

 

 

 

 

PART III 

 

 

 

 

 

 

 

Item 10 

 

Directors, Executive Officers and Corporate Governance

 

159

Item 11 

 

Executive Compensation

 

159

Item 12 

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

159

Item 13 

 

Certain Relationships and Related Transactions, and Director Independence

 

159

Item 14 

 

Principal Accountant Fees and Services

 

159

 

 

 

 

 

PART IV 

 

 

 

 

 

 

 

Item 15 

 

Exhibits and Financial Statement Schedules

 

160

Item 16 

 

Form 10‑K Summary

 

160

Signatures 

 

 

 

166

 

 

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GLOSSARY OF TERMS

Industry Terms

Below is a list of terms that are common to our industry and used throughout this Form 10‑K:

Bbl

 

Standard barrel containing 42 U.S. gallons

 

MMBbl

 

One million Bbls

Mcf

 

One thousand cubic feet

 

MMcf

 

One million cubic feet

Btu

 

One British thermal unit

 

MMBtu

 

One million Btu

BOE

 

Barrel of oil equivalent. Natural gas is converted into one BOE based on six Mcf of gas to one barrel of oil

 

MBOE

 

One thousand BOEs

DD&A

 

Depreciation, Depletion and Amortization

 

MMBOE

 

One million BOEs

Bcf

 

One billion cubic feet

 

NGLs

 

Natural gas liquids

BPD

 

Barrels per day

 

 

 

 

 

Completion refers to the work performed and the installation of permanent equipment for the production of natural gas and/or crude oil from a recently drilled or recompleted well.

Costs and expenses include direct and indirect expenses, including general and administrative expenses, incurred to manage, operate and maintain wells and related equipment and facilities.

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

Dry Well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploitation is activity undertaken to increase value or realize full value in oil and natural gas field.

Exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well or a service well.

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. For a complete definition of a field, refer to Rule 4‑10(a)(8) of Regulation S-X as promulgated by the Securities and Exchange Commission (“SEC”).

Formation is a stratum of rock that is recognizable from adjacent strata consisting mainly of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.

Gathering and transportation is the cost of moving crude oil or natural gas to the point of sale.

Gross acres or gross wells are the total acres or wells in which a working interest is owned.

Horizon is a zone of a particular formation or that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

Independent oil and gas company is a company that is primarily engaged in the exploration and production sector of the oil and gas business.

Lease operating or well operating expenses are expenses incurred to operate the wells and equipment on a producing lease.

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Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the fractional working interest owned in the properties.

NGL refers to natural gas liquids.

Oil includes crude oil and condensate.

Pipeline facility fee is the straight line lease expense attributable to certain real and personal property constituting a subsea pipeline gathering system located in the shallow Gulf of Mexico shelf and storage and onshore processing facilities at Grand Isle, Louisiana (“GIGS”).

Plugging and abandonment refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from a stratum will not escape into another or to the surface and the removal of associated equipment. Regulations of many states and the federal government require the plugging of abandoned wells.

Production costs are costs incurred to operate and maintain our wells and related equipment and facilities. For a complete definition of production costs, please refer to Rule 4‑10(a)(20) of Regulation S-X as promulgated by the SEC.

Productive well is an exploratory, development or extension well that is not a dry well.

Proved area refers to the part of a property to which proved reserves have been specifically attributed.

Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. For a complete definition of proved reserves, refer to Rule 4‑10(a)(22) of Regulation S-X as promulgated by the SEC.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. For a complete definition of proved developed oil and gas reserves, refer to Rule 4‑10(a)(3) of Regulation S-X as promulgated by the SEC.

Proved undeveloped reserves are 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. For a complete definition of proved undeveloped oil and gas reserves, refer to Rule 4‑10(a)(4) of Regulation S-X as promulgated by the SEC.

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

Seismic is an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formations. 2‑D seismic provides two-dimensional information and 3‑D seismic provides three-dimensional pictures.

Unevaluated properties refers to properties for which a determination has not been made as to whether the property contains proved reserves.

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

Workover refers to the operations on a producing well to restore or increase production and such costs are expensed. If the operations add new proved reserves, such costs are capitalized.

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Zone is a stratigraphic interval containing one or more reservoirs.

Other Terms

EPL Acquisition refers to the acquisition of EPL Oil & Gas Inc. on June 3, 2014 by EXXI Ltd.

Tax Code means the Internal Revenue Code of 1986, as amended, including changes made by the Tax Cuts and Jobs Act of 2017 (as defined below).

Tax Cuts and Jobs Act of 2017 refers to the Tax Cuts and Jobs Act of 2017, enacted on December 22, 2017.

Bankruptcy Terms

On April 14, 2016 (the “Petition Date”), Energy XXI Ltd (“EXXI Ltd”), an exempt company incorporated under the laws of Bermuda and predecessor of the registrant under this Form 10‑K for the year ended December 31, 2017 (this “Form 10‑K”), Energy XXI Gulf Coast, Inc., then an indirect wholly-owned subsidiary of EXXI Ltd (“EGC”), EPL Oil & Gas Inc., an indirect wholly-owned subsidiary of EXXI Ltd (“EPL”) and certain other indirect wholly-owned subsidiaries of EXXI Ltd filed voluntary petitions for reorganization in the United States Bankruptcy Court for the Southern District of Texas, Houston Division seeking relief under the provisions of chapter 11 of Title 11 of the United States Code.

In connection therewith, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to EGC (the “Reorganized EGC”). On December 30, 2016 (the “Emergence Date”), the entities emerged from bankruptcy and shares of common stock and common stock warrants of Reorganized EGC were distributed to creditors of the Debtors’ (defined below) pursuant to the Plan (defined below). In accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), the Reorganized EGC was required to apply fresh start accounting upon EXXI Ltd’s emergence from bankruptcy and it evaluated transaction activity between the Emergence Date and December 31, 2016 and concluded that an accounting convenience date of December 31, 2016 (the “Convenience Date”) was appropriate.

As used throughout this Form 10‑K, references to “EGC”, the “Company,” “we,” “our”, “Successor”, “Successor Company” or similar terms when used in reference to the period subsequent to the emergence from the bankruptcy refer to Reorganized EGC, the new parent entity and successor issuer of EXXI Ltd pursuant to Rule 12g‑3(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). References in this Form 10‑K to “EXXI Ltd,” “we,” “our”, “Predecessor”, “Predecessor Company” or similar terms when used in reference to the periods prior to the emergence from the bankruptcy refer to Energy XXI Ltd, the predecessor and former parent entity that was dissolved upon the completion of the Bermuda Proceeding (as defined below).

Below is a list of additional terms relating to the bankruptcy as used throughout this Form 10‑K:

Bankruptcy Code means title 11 of the United States Code, as amended and in effect during the pendency of the Chapter 11 Cases.

Bankruptcy Court means the United States Bankruptcy Court for the Southern District of Texas, Houston Division.

Bankruptcy Petitions means the Debtors’ voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11 under the caption In re Energy XXI Ltd, et al., Case No. 16‑31928.

Bermuda Proceeding means the official liquidation proceeding for EXXI Ltd under the laws of Bermuda commenced pursuant to the winding-up petition before the Bermuda Court and completed as of June 29, 2017.

Bermuda Court means the Supreme Court of Bermuda, Commercial Court.

Chapter 11 means chapter 11 of the Bankruptcy Code.

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Chapter 11 Cases means the Debtors’ procedurally consolidated and jointly administered Chapter 11 cases in the Bankruptcy Court.

Confirmation Hearing means the hearing of the Bankruptcy Court to consider confirming the Plan pursuant to section 1129 of the Bankruptcy Code.

Confirmation Order means the order dated December 13, 2016 entered by the Bankruptcy Court approving and confirming the Plan pursuant to section 1129 of the Bankruptcy Code.

Convenience Date means December 31, 2016.

Debtors means, collectively, the following: Anglo-Suisse Offshore Pipeline Partners, LLC, Delaware EPL of Texas, LLC, Energy Partners Ltd., LLC, Energy XXI GOM, LLC, Energy XXI Gulf Coast, Inc., Energy XXI Holdings, Inc., Energy XXI, Inc., Energy XXI Leasehold, LLC, Energy XXI Ltd, Energy XXI Natural Gas Holdings, Inc., Energy XXI Offshore Services, Inc., Energy XXI Onshore, LLC, Energy XXI Pipeline, LLC, Energy XXI Pipeline II, LLC, Energy XXI Services, LLC, Energy XXI Texas Onshore, LLC, Energy XXI USA, Inc., EPL of Louisiana, L.L.C., EPL Oil & Gas, Inc., EPL Pioneer Houston, Inc., EPL Pipeline, L.L.C., M21K, LLC, MS Onshore, LLC, Natural Gas Acquisition Company I, LLC, Nighthawk, L.L.C., and Soileau Catering, LLC.

Disclosure Statement means the Debtors’ Third Amended Disclosure Statement (as amended, modified, or supplemented from time to time).

Disclosure Statement Supplement means the solicitation version of the Second Supplement to the Disclosure Statement Setting Forth Modifications to the Plan (as amended, modified, or supplemented from time to time).

Emergence Date means December 30, 2016.

Non-Debtors means all of EXXI Ltd’s wholly and not-wholly owned subsidiaries who were not Debtors in the Chapter 11 Cases, including: (a) Energy XXI Insurance Limited; (b) Energy XXI M21K, LLC; (c) Energy XXI GIGS Services, LLC; (d) Energy XXI (US Holdings) Limited; (e) Energy XXI International Limited; (f) Energy XXI Malaysia Limited; and (g) Ping Petroleum Limited.

Petition Date means April 14, 2016.

Plan means the Second Amended Proposed Joint Chapter 11 Plan of Reorganization (as amended, modified, or supplemented from time to time).

Provisional Liquidator means John C. McKenna, as appointed by the Bermuda Court.

Reorganized Debtors means the Debtors after completing the series of internal reorganization transactions pursuant to which, among other things, EXXI Ltd transferred all of its remaining assets to EGC.

 

 

 

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Form 10‑K may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Company believes are appropriate under the circumstances and their potential effect on us. While management believes that these forward-looking statements are reasonable, such statements are not guarantees of future performance and the actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Company’s business or results. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to those summarized below:

·

our ability to maintain sufficient liquidity and/or obtain adequate additional financing necessary to (i) maintain our infrastructure, particularly in light of its maturity, high fixed costs, and required level of maintenance and repairs compared to other Gulf of Mexico shelf producers, (ii) fund our operations, capital expenditures and to execute our business plan, develop our proved undeveloped reserves within five years and (iii) meet our other obligations, including plugging and abandonment and decommissioning obligations;

·

new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value could vary significantly from current or future estimates;

·

our future financial condition, results of operations, revenues, expenses and cash flows;

·

our current or future levels of indebtedness, liquidity, compliance with financial covenants and our ability to continue as a going concern;

·

the effects of the departure of our former senior leaders and the hiring of a new Chief Executive Officer (“CEO”), Chief Operating Officer (“COO”) and Chief Financial Officer (“CFO”) on our employees, suppliers, regulators and business counterparties;

·

recent changes (including announced future changes) in the composition of our board of directors of the Company (the “Board”);

·

our inability to retain and attract key personnel;

·

our ability to post collateral for current or future bonds or comply with any new regulations or Notices to Lessees and Operators (“NTLs”) imposed by the Bureau of Ocean Energy Management (the “BOEM”);

·

our ability to comply with covenants under the three-year secured credit facility (the “Exit Facility”) entered into by the Company as the borrower and the other Reorganized Debtors;

·

changes in our business strategy;

·

sustained or further declines in the prices we receive for our oil and natural gas production;

·

economic slowdowns that can adversely affect consumption of oil and natural gas by businesses and consumers;

·

geographic concentration of our assets;

·

our ability to make acquisitions and to integrate acquisitions;

 

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·

our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;

·

our inability to maintain relationships with suppliers, customers, employees and other third parties;

·

uncertainties in estimating our oil and natural gas reserves and net present values of those reserves;

·

the need to take ceiling test impairments due to lower commodity prices using SEC methodology, under which, commodity prices are computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12‑month period;

·

future derivative activities that expose us to pricing and counterparty risks;

·

our ability to hedge future oil and natural gas production may be limited by lack of available counterparties;

·

our ability to hedge future oil and natural gas production may be limited by financial/seasonal limits as required under our Exit Facility;

·

our degree of success in replacing oil and natural gas reserves through capital investment;

·

uncertainties in exploring for and producing oil and natural gas, including exploitation, development, drilling and operating risks;

·

our ability to establish production on our acreage prior to the expiration of related leaseholds;

·

availability and cost of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;

·

disruption of operations and damages due to capsizing, collisions, hurricanes, tropical storms or maintenance or repairs of infrastructure and equipment;

·

environmental risks;

·

availability, cost and adequacy of insurance coverage;

·

competition in the oil and natural gas industry;

·

the effects of government regulation and permitting and other legal requirements;

·

costs associated with perfecting title for mineral rights in some of our properties; and

·

uncertainty of our ability to improve our operating structure, financial results and profitability following emergence from Chapter 11 and other risks and uncertainties related to our emergence from Chapter 11.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read (1) Part I, Item 1A. “Risk Factors” and elsewhere in this Form 10‑K, (2) our reports and registration statements filed from time to time with the SEC and (3) other public announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date upon which they are made, whether as a result of new information, future events or otherwise.

 

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PART I

Item 1.  Business

General Information

Energy XXI Gulf Coast, Inc. (“EGC” or the “Company”) was formed in December 2016 after emerging from a voluntary reorganization under Chapter 11 proceedings as the restructured successor of Energy XXI Ltd (“EXXI Ltd”).  Upon emergence, a new Board was put in place and throughout the year a new management team was assembled. We are headquartered in Houston, Texas, and engage in the development, exploitation, and operation of oil and natural gas properties primarily offshore on the Gulf of Mexico Shelf (“GoM Shelf”), which is an area in less than 1,000 feet of water, and also onshore in Louisiana and Texas. We own and operate nine of the largest GoM Shelf oil fields ranked by total cumulative oil production to date and utilize various techniques to increase the recovery factor and thus increase the total oil recovered. At December 31, 2017, our total proved reserves were 88.2 MMBOE of which 84% were oil and 75% were classified as proved developed. We operated or had an interest in 577 gross producing wells on 421,974 net developed acres, including interests in 55 producing fields.

Our geographic concentration on the GoM Shelf exposes us to various challenges, including: a high operating cost environment, operational risks related to hurricanes and storms, relatively steep decline curves, permitting and other regulatory requirements and plugging and abandonment liabilities.  Over the past year, we have proactively focused our operating plan to address these challenges, including: optimizing our development activity and controlling our operating costs through sole sourcing, consolidating facilities, and other cost-cutting initiatives.

Corporate Identity Update and Ticker Symbol Change

To better reflect our corporate identity as Energy XXI Gulf Coast, Inc., on March 16, 2018, we announced the change of our NASDAQ Global Select Market (“NASDAQ”) ticker symbol for our common stock from “EXXI” to “EGC”.   Our common stock began trading on the NASDAQ under the symbol “EGC” at the opening of business on March 21, 2018.  In conjunction with our corporate re-branding, on March 21, 2018, we adopted a refreshed corporate logo and launched an updated website that provides details on the Company’s updated vision and strategy.

Competitive Strengths

Strong Management and Technical Expertise.  Our seasoned and diverse management team averages over 32 years of industry experience with significant expertise in the Gulf of Mexico and the U.S. Gulf Coast area.  We have assembled a knowledgeable technical team of engineers, geologists and geophysicists who play a key role in the execution of our strategy.  Our engineers have an average of 17 years of industry experience and our team of geologic and geophysical experts average 32 years of industry experience. 

Oil-Weighted Asset Base. We believe the high percentage of oil in our reserves and production provides us with an economic advantage that enhances stockholder value.  At year-end 2017, crude oil reserves constitute 84% of our total proved reserves.  Additionally, our production decline curve for oil in our GoM Shelf fields is typically lower than a comparable natural gas decline curve, resulting in longer-term production of our current reserves.  In the fourth quarter of 2017, crude oil consisted of 77% percent of our total equivalent production.

Our Legacy as a Gulf of Mexico Operator.  As a publicly traded operator with the largest asset portfolio on the GoM Shelf, based on cumulative production to date, we believe our multi-year operating history, experienced technical team and strong working relationships with BOEM and BSEE have established our position as a leading operator in the Gulf of Mexico.  Our legacy position in the GoM shelf area has enhanced our subsurface knowledge and operational expertise that can be employed in key plays in both deeper waters of the GoM as well as onshore areas in Louisiana and Texas.

Operating Efficiencies. We currently operate 89% of our proved reserves, all of which are currently located on the GoM Shelf, or onshore along the U.S. Gulf Coast.  As a result, we are afforded greater control of the optimization of

 

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production, the timing and amount of capital expenditures and the costs of our projects.  In addition, our multiple wellbore locations provide diversification of our production and reserves. 

Footprint on the GoM Shelf. Our geographical concentration on the GoM Shelf enables us to manage our operated fields with greater efficiencies and cost saving synergies. We believe our operational infrastructure and capacity places us in an advantageous position to aggregate properties and take on new development projects. 

Business Strategy

Our strategy is to leverage our operational, technical and commercial expertise in conventional resource development to grow value by developing and exploiting our considerable GoM Shelf resource base. We also are positioned to target select acquisitions where our conventional drilling and development expertise can be readily deployed in both shallow water and deeper water opportunities, as well as onshore conventional plays, which could diversify our asset portfolio and reduce our per unit operating costs. Additionally, we also are evaluating divestiture of non-strategic assets.

The key facets of our strategy include:

Operate Safely and Comply with Environmental Operating Standards. Our strategy has a firm foundation built on our core values of safety, relationships, integrity, accountability, innovation and community.  Excellence in safety and environmental stewardship are top priorities that guide our decision making and risk management.  

 

Execute Our Development and Exploitation Drilling Program in Core Areas.  Our current producing resource base includes a number of future drilling locations, predominantly in our well-established core areas. We plan to add new production and reserves by developing our inventory of both lower-risk proved undeveloped drilling locations as well as exploitation locations in a disciplined manner. Successful drilling of exploitation locations can have a meaningful positive impact on our reserves and production. We utilize various techniques that enable us to replenish our large inventory of drilling opportunities while continuing to drill in these prolific oil reservoirs when there are adequate funds to do so. Our 2018 capital expenditure program consists of six wells located in our core areas in West Delta and South Timbalier and focuses on arresting our natural production declines.

 

Maximize our Financial Flexibility. We are committed to driving financial discipline throughout our organization. We have spent the last twelve months evaluating our business and aligning operational costs with forecasted needs in order to maximize our financial flexibility. Our focus will remain on maintaining a conservative balance sheet, lowering costs to increase margins and preserve optionality to capitalize on an increase in prices and sustainable cost reductions and optimizing savings in multiple categories.  At December 31, 2017, liquidity totaled approximately $164.2 million, which was comprised of cash and cash equivalents totaling $151.7 million and $12.5 million in borrowing capacity available under certain conditions.  Additional sources of capital, if obtained, could strengthen our balance sheet and fund new growth opportunities, including accelerated drilling on our core properties, and targeted acquisitions that complement our current portfolio and utilize our core strengths.

 

Proactively Manage our Asset Retirement Obligations. We remain focused on proactively addressing our asset retirement and decommissioning obligations.  Plugging and abandonment expenditures are an ongoing part of doing business in the GoM and we have an internal team that is focused on how to meet those obligations on a timely and cost effective basis. Our capital expenditures plan for 2018 consists of spending approximately $50 to $60 million dollars on plugging and abandonment activities, similar to $52.7 million dollars spent on those activities in 2017. 

 

Seek New Growth Opportunities. We have the skills to diversify our asset portfolio and reduce our per unit operating costs by targeting select acquisitions where our conventional drilling and development expertise can be deployed in both shallow water and deeper water opportunities, as well as onshore conventional plays.  As we look to increase efficiencies and optimize our infrastructure, we are also considering the divestment of non-strategic assets.  We remain receptive to possible consolidation transaction in our GoM shelf area which could create significant synergies through operating and overhead cost savings.

 

 

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Protect Against Commodity Price Exposures. We utilize commodity-based derivative instruments with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas.  We have historically used various instruments, including financially settled crude oil and natural gas puts, put spreads, swaps, costless collars and three-way collars in our derivative portfolio.  Any gains or losses resulting from the change in fair value from hedging transactions and from the settlement of hedging contracts are recorded in earnings as a component of revenues.

 

General Information on Properties

Below are descriptions of our significant properties at December 31, 2017.

Main Pass 61 Field.  We operate and have a 100% working interest in the Main Pass 61 field, located near the mouth of the Mississippi River in approximately 90 feet of water.  The field consists of federal OCS blocks Main Pass 60, 61, and 62.  Initially discovered by Pogo Producing Company in 2000, the field has produced in excess of 66 MMBOE since production first began in 2002, from four Upper Miocene sands.  The primary producer is the J-6 Sand, which consists of a series of stratigraphic reservoirs deposited in an outer shelf/upper slope channel/levee/overbank complex deposited on the regional south dip. The two larger J-6 Sand reservoirs, pods A and B are oil reservoirs that are being water-flooded to maintain reservoir pressure and maximize recovery. There are 28 producing wells and three major production platforms located throughout the field.  The field’s net production for December 2017 of 2.8 MBOE/Day (“MBOED”) accounted for approximately 9.9% of our net production.  Net proved reserves for the field were 85.9% oil at December 31, 2017. 

Ship Shoal 208 Field.  We operate and have a 100% working interest in the Ship Shoal 208 Field, located 110 miles southwest of New Orleans, Louisiana in approximately 100 feet of water on OCS blocks Ship Shoal 208, 209 and 215. The field was acquired through the EPL Acquisition.  The Ship Shoal 208 Field surrounds a large salt dome and produces from over 30 Upper and Lower Pliocene reservoir. The field was discovered by Pure Energy in 1960 and has produced in excess of 459 MMBOE since production first began in 1963. We have 13 platforms and 25 active wells throughout the field. The field’s net production for December 2017 of 1.9 MBOED accounted for approximately 6.5% of our net production.  Net proved reserves for the field were 90.2% oil at December 31, 2017. This field is the ninth largest oil field on the GoM Shelf, based on cumulative production to date.

South Pass 49 Field.  We operate and have a 100% working interest in the South Pass 49 field, which is located near the mouth of the Mississippi River in approximately 400 feet of water. The field was discovered by Gulf Oil in 1974.  The field produces from Lower Pliocene sands, which consist of the Discorbis 20 thru Discorbis 70 sands, ranging in depths from 7,600 feet to 9,400 feet, on OCS blocks South Pass 33, 48, and 49.  There are 13 active wells located throughout the field.  Production is processed through one central production platform, and the field has produced in excess of 112 MMBOE.  The field’s net production for December 2017 of 1.7 MBOED accounted for approximately 6.1% of our net production.  Net proved reserves for the field were 65.0% oil at December 31, 2017. 

South Pass 78. We operate and own 100% working interest in the South Pass 78 complex.  The complex includes portions of South Pass blocks 57, 58, 78 and all of 77 and is located 86 miles southeast of New Orleans in water depths ranging from 140 to 190 feet.  Pennzoil Energy Co. discovered the field in 1972. To date the field has produced in excess of 240 MMBOE from 68 stacked oil and gas reservoir, ranging in depths from -3000’ to -15300’ TVDSS.  The field is dominated by a large piercement salt dome, with its shallowest penetration being in the southwest corner of block 57. Hydrocarbons are trapped in the field by a combination of faulting and/or complex stratigraphy associated with the reservoir sands. The reservoirs range in age from Lower Pleistocene to Upper Miocene. There are four major production platforms, which have 28 actively producing wells. The field’s net production for December 2017 of 1.4 MBOED accounted for approximately 4.9% of our net production.  Net proved reserves for the field were 64.5% oil at December 31, 2017. 

South Timbalier 21. We operate and have a 100% working interest in the South Timbalier 21 area, located six to ten miles offshore of Lafourche Parish, Louisiana in approximately 55 feet of water on OCS blocks South Timbalier 21, 22, 23, 26, 27, 28 and 41, as well as on two state leases. Block 26 and 41 were acquired through the EPL Acquisition.  The South Timbalier 21 area, discovered by Gulf Oil Company and Shell Oil Company in the late 1950s and 1960s, has produced in excess of 596 MMBOE since production began in 1957, with the exception of South Timbalier 41,

 

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discovered by EPL in 2004, which has produced in excess of 25 MMBOE.  The field is bounded on the north by a major Miocene expansion fault. Miocene sands are trapped structurally and stratigraphically from 7,000 feet to 15,000 feet in depth. A large counter-regional fault, along with salt and smaller faults, creates traps and separates hydrocarbon accumulations into individual compartments. There are 23 major production platforms, 29 smaller structures and 48 active wells located throughout the fields. The area’s net production for December 2017 of 1.5 MBOED accounted for approximately 5.2% of our net production.  Net proved reserves for the field were 77.2% oil at December 31, 2017. 

South Timbalier 54 Field. We operate and have a 100% working interest in the South Timbalier 54 field, located 36 miles offshore of Lafourche Parish, Louisiana in approximately 67 feet of water on the OCS. The field was originally discovered in 1955 by Humble Oil and Refining. The field is at the confluence of regional and counter-regional fault systems. Pleistocene through Miocene sands are trapped from 4,800 feet to 17,000 feet in shallow low relief structures over a deeper seated salt dome and in combinations of structural and stratigraphic traps against salt at depth. Minor faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 153 MMBOE. There are six production platforms and 27 active wells located throughout the field. The field’s net production for December 2017 of 1.9 MBOED accounted for approximately 6.6% of our net production.  Net proved reserves for the field were 75.8% oil at December 31, 2017.    

West Delta 30 Field.  We operate eight of the twelve blocks that comprise the West Delta Block 30 Field.  Our working interests range from 84% to 100%. The field lies in United States Federal waters about 21 miles south of Grand Isle, Louisiana.  Water depth is from twenty to sixty feet.  The field was discovered in 1948 by Humble Oil and Refining Company.  Hydrocarbon accumulations are set up by a salt dome on the western side of the field and a large counter regional fault running east-west through the middle of the field.  Productive sands range from 2,000 feet deep to 17,500 feet deep and generally produce via a strong water drive. Traps are both structural and stratigraphic.  The field has produced in excess of 752 MMBOE. There are 45 production structures and 80 active wells in the field. The field’s net production for December 2017 of 3.4 MBOED accounted for approximately 11.9% of our net production. Net proved reserves for the field were 88.3% oil at December 31, 2017.  This field is the second largest oil field on the GoM Shelf, based on cumulative production to date.

West Delta 73 Field.  We operate and have a 100% working interest in the West Delta 73 field, located 28 miles offshore of Grand Isle, Louisiana in approximately 175 feet of water on the Outer Continental Shelf (“OCS”). The field, which was first discovered in 1962 by Humble Oil and Refining, is a large low relief faulted anticline.  The field produces from Pleistocene through Upper Miocene aged sands trapped structurally on the high side closures over the large anticlinal feature from 1,500 feet to 13,000 feet.  The field has produced in excess of 392 MMBOE. There are seven production platforms and 46 active wells located throughout the field.  The field’s net production for December 2017 of 2.3 MBOED accounted for approximately 8.2% of our net production.  Net proved reserves for the field, which is our largest field based upon net proved reserves, were 93.9% oil at December 31, 2017. This field is the tenth largest oil field on the GoM Shelf, based on cumulative production to date.

Reserve Estimation Procedures and Internal Controls over Reserve Estimates

From June 30, 2013 through June 30, 2016, the Company utilized third-party engineers to audit its internal calculations of reserves and as of December 31, 2016, the reserve quantities were estimated and compiled by its internal reservoir engineers. The Company did not have a fully-engineered third-party report prepared since 2012.  Under the terms of its First Lien Exit Credit Agreement executed in 2016, a third party engineer report was required annually, with the first report due by May 31, 2017. As a result, we had a fully-engineered report prepared by Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm (“NSAI”) as of March 31, 2017.   

NSAI’s report estimated total proved reserves as of March 31, 2017 to be 109.4 MMBOE, of which 80% were oil, 2% were natural gas liquids, and 18% were natural gas. SEC 12-month average NYMEX pricing on March 31, 2017 was $44.10 per BBL and $2.73 per MMBTU, before differentials.  The PV-10 Value on that date was $108.4 million. By comparison, in the Company’s year-end 2016 internally-prepared report, total proved reserves were 121.9 MMBOE and the PV-10 was $135.4 million, using a crude oil price of $42.74 per BBL and $2.48 per MMBTU, before differentials.  The primary non-commodity price factors contributing to the difference between the NSAI March 31, 2017 SEC report and the internally-prepared year-end 2016 report were: (i) technical reassessments, (ii) higher capital costs and

 

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(iii) production during the first quarter of 2017.  The impact of those factors was partially offset by higher SEC average commodity prices for both crude oil and natural gas.

The estimates included in this Form 10-K of our proved reserves were also prepared by NSAI and include estimates for all of the proved reserves attributable to our net interests in oil and natural gas properties as of December 31, 2017.  The scope and results of NSAI’s procedures are summarized in a report, which is included as Exhibit 99.1 to this Form 10-K.  For further information on reserves, including information on future net cash flows and the standardized measure of discounted future net cash flows, see “Item 8.  Financial Statements and Supplementary Data - Supplemental Oil and Gas Information (Unaudited).” 

In the process of estimating our proved reserves, NSAI used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests and by employing deterministic methods in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (“SPE Standards”).  NSAI also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance and conform to ASC 932, Extractive Activities – Oil and Gas

Internal Control and Qualifications of Third Party Engineers and Internal Staff 

The technical persons primarily responsible for preparing the estimates at NSAI meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.  Connor B. Riseden, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2006 and has over 4 years of prior industry experience.  Shane M. Howell, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry experience.  NSAI is a firm of independent petroleum engineers, geologists, geophysicists and petrophysicists.  NSAI does not own an interest in our properties nor is NSAI employed on a contingent basis. 

   Our internal controls over reserves estimates include reconciliation and review controlsOur internal reservoir engineers work closely with representatives of NSAI to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. We provide historical information to NSAI, including ownership interest, oil and gas production, well test data, and operating and development costs. In the conduct of their preparation of the reserve estimates, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, well test data, historical costs of operation and development or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its work, something came to NSAI’s attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data without first satisfactorily resolving the questions they had about such information or data.  Our Director of Reserves, Lee I. Williams, is the technical person primarily responsible for overseeing the internal reserve estimation process and also to provide the appropriate data to NSAI for its reserves estimation process. Mr. Williams has 17 years of industry experience with positions of increasing responsibility and has over 14 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1998 with a Bachelor of Science Degree in Petroleum Engineering.  The NSAI reserve report is reviewed with representatives of NSAI and our senior management and Director of Reserves before dissemination of the information. Additionally, a summary of the NSAI reserve report is presented to our Board for its review. 

Technologies Used in Reserve Estimation

The SEC allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” is defined by the SEC as “much more likely to be produced than not” and “much more likely to increase or remain constant than to decrease.” NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, pressure data and reservoir simulation. There are numerous uncertainties inherent in estimating quantities of reserves and in

 

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projecting future rates of production and timing of development expenditures, including many factors beyond our control. Accordingly, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.  

Summary of Oil and Gas Reserves at December 31, 2017

The following estimates of the net proved reserves of our oil and natural gas properties located entirely within the U.S. are based on estimates prepared by NSAI. Reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost changes except by contractual arrangements. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available. Please read Item 1A. Risk Factors Estimates of reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

Summary of Oil and Natural Gas Reserves as of December 31, 2017 Based on Average Twelve Month Period Prices

 

    

Oil
MMBbls

    

NGLs
MMBbls

    

Natural
Gas Bcf

    

MMBOE

    

Percent of
Total
Proved

    

PV-10

(in thousands)(1)(2)(3)

Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

55.0

 

1.4

 

58.9

 

66.2

 

75%

 

$

(149.1)

Undeveloped

 

19.4

 

0.3

 

14.1

 

22.0

 

25%

 

 

164.2

Total proved

 

74.4

 

1.7

 

73.0

 

88.2

 

 

 

 

15.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future income taxes

 

 

 

 

 

 

 

 

 

 

 

 

 —

Less present value discount at 10%

 

 

 

 

 

 

 

 

 

 

 

 

 —

Future income taxes discounted at 10%

 

 

 

 

 

 

 

 

 

 

 

 

 —

Standardized measure of future discounted net cash flows

 

 

 

 

 

 

 

 

 

 

 

$

15.1


(1)

We refer to “PV‑10” as the present value of estimated future net revenues of estimated proved reserves using a discount rate of 10%. This amount includes projected revenues less estimated production costs, abandonment costs and development costs but does not include effects, if any, of income taxes, as described below. PV‑10 is not a financial measure prescribed under accounting principles generally accepted in the U.S. (“U.S. GAAP”); therefore, the table reconciles this amount to the standardized measure of discounted future net cash flows, which is the most directly comparable U.S. GAAP financial measure. Management believes that the non-U.S. GAAP financial measure of PV‑10 is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV‑10 is used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. We believe the use of this pre-tax measure is valuable because there are unique factors that can impact an individual company when estimating the amount of future income taxes to be paid. Management believes that the presentation of PV‑10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV‑10 is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV‑10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under U.S. GAAP. Average prices (calculated using the average of the first-day-of-the-month commodity prices during the 12‑month period ended on December 31, 2017) used in determining future net revenues were $47.79 per barrel of oil for West Texas Intermediate  (“WTI”) benchmark plus $3.20 per barrel for crude quality and location differentials, for a total of $50.99 per barrel. For NGLs, the average price used was $26.79 per barrel. For natural gas, the average price used was $2.98 per MMBtu utilizing the Henry Hub benchmark less adjustments for gas quality, BTU content and location differentials, for a total of $2.85 per Mcf.

 

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(2)

We recorded no future income taxes primarily due to our inability to currently record any additional deferred tax assets. Further, the elimination of our U.S. federal income tax net operating loss (“NOL”) carryforwards and the reduction in tax basis of our properties upon emergence from Chapter 11 may subject us to cash income taxes after the Convenience Date, which may have an impact on our standardized measure of discounted future net cash flows.

(3)

The negative value for proved developed reserves results from discounted plugging and abandonment costs exceeding the discounted cash flows from the developed reserves.  This is due to allocating all of the plugging and abandonment costs to the proved developed reserves.  The development of the proved undeveloped reserves is expected to generate positive cash flow for the total proved reserves.

Changes in Proved Reserves

From June 30, 2013 through June 30, 2016, the Company utilized third-party engineers to audit its internal calculations of reserves and as of December 31, 2016, the reserve quantities were estimated and compiled by its internal reservoir engineers. The Company did not have a fully-engineered third-party report prepared since 2012.  Under the terms of its First Lien Exit Credit Agreement executed in 2016, a third party engineer report was required annually, with the first report due by May 31, 2017. As a result, we had a fully-engineered report prepared by NSAI as of March 31, 2017, and the Company plans to have any future annual reserve reports fully-engineered by a third-party engineering firm.   Therefore, the estimates included in this Form 10-K of our proved reserves as of December 31, 2016 were internally generated, while the proved reserves attributable to our net interests in oil and natural gas properties as of December 31, 2017 were fully engineered by NSAI. Our proved reserves decreased by 33.7 MMBOE or by approximately 28% from 121.9 MMBOE at December 31, 2016 to 88.2 MMBOE as of December 31, 2017. The decrease was primarily due to:

·

17.4 MMBOE of negative revisions of proved undeveloped reserves.  These reserves were written off primarily due to updated technical assessments of undeveloped reserves and, due to delayed drilling activity during 2017 and changes to the Company’s drilling schedule, the SEC’s requirement that undeveloped reserves be developed within five years of the initial booking. 

·

12.5 MMBOE of production during the period.

·

10.7 MMBOE of reserves that became uneconomic due to increased estimates of lease operating expenses.

·

9.6 MMBOE of negative revisions of proved developed non-producing reserves.  Of these negative revisions, 4.2 MMBOE were primarily due to the revised drilling schedule truncating proved economic field lives and 5.2 MMBOE were due to updated technical assessments.

These were offset by:

·

7.1 MMBOE of new reserves that were added after technical reviews of the assets.

·

Upward revisions of 7.0 MMBOE of reserves due to increased product prices and improved field economics.

·

Upward revisions of 3.3 MMBOE of proved developed producing reserves due to performance. 

Development of Proved Undeveloped Reserves

Due to depressed commodity prices and EXXI Ltd’s lack of capital resources to develop its properties, the proved undeveloped oil and natural gas reserves no longer qualified as being proved as of December 31, 2015. As a result, EXXI Ltd removed all of its proved undeveloped oil and natural gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category on December 31, 2015 were still economic at prices and costs applicable to SEC reserve reports at such date, but were

 

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reclassified to the contingent resource category because they were no longer expected to be drilled within five years of initial booking due to then current constraints on EXXI Ltd’s ability to fund development drilling.

Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the then renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million. As of December 31, 2017, the Company had proved undeveloped reserves of 22.0 MMBOE with future development costs of $356.1 million.

The plan to drill and develop the Company’s undeveloped reserves is updated and approved on an annual basis.  Updates to the plan are based upon a variety of criteria, including changes in market conditions, maximization of present value, cash flow and production volumes, drilling obligations, five-year rule requirements, and anticipation of certain drilling rig types.  Due to these multiple, dynamic factors, the plan and its implementation is reviewed by senior management and the Board throughout the year as market conditions change.  The relative portion of total proved undeveloped reserves that the Company develops will not be uniform from year to year, but will vary by year depending upon the factors that affect the drilling plan; including financial targets such as reducing debt, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves or non-proved prospects.  As scheduled in our long range plan, all of our proved undeveloped locations are expected to be developed within five years from the time they were first recognized as proved undeveloped locations in the Company’s reserves report.

Our current proved undeveloped schedule is also subject to change due to external factors such as changes in commodity prices, the availability of capital, acquisitions, regulatory matters and the availability of drilling rigs that are capable of drilling in a given area. Senior management continuously monitors our development drilling plan to ensure that there is reasonable certainty of proceeding with our development plans and informs the Board of any required changes to the existing long range plan and the related development plan. The following table presents the percentage of proved undeveloped reserves scheduled to be developed by fiscal year, in accordance with our long range plan.

 

 

 

 

 

 

Successor

 

Year Ending December 31, 

    

Percentage of Proved
Undeveloped Reserves
Scheduled to be Developed

 

2018

 

12.0

%

2019

 

28.0

%

2020

 

23.0

%

2021

 

37.0

%

Total

 

100.0

%

 

 

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The following table discloses our progress toward the conversion of proved undeveloped reserves during the fiscal year ended December 31, 2017.

 

 

 

 

 

 

 

Oil and
Natural Gas

 

Future Development Costs

 

 

(MBOE)

 

 

(in thousands)

Proved undeveloped reserves at December 31, 2016

 

36,498

 

$

443,172

Extensions, discoveries and other additions

 

4,754

 

 

104,388

Revisions of previous estimates

 

(19,213)

 

 

(191,477)

Total reduction in proved undeveloped reserves

 

(14,459)

 

 

(87,089)

Proved undeveloped reserves at December 31, 2017

 

22,039

 

$

356,083

Drilling Activity

The following table sets forth our drilling activity.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

Predecessor

 

 

 

Year Ended

 

 

Six Months Ended

 

Year Ended June 30,

 

 

 

December 31, 2017

 

 

December 31, 2016

 

2016

 

2015

 

 

    

Gross

    

Net

  

  

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

 

Productive wells drilled

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development

 

1.0

 

1.0

 

 

 —

 

 —

 

1.0

 

1.0

 

21.0

 

21.0

 

Exploratory

 

 —

 

 —

 

 

 —

 

 —

 

 —

 

 —

 

3.0

 

1.7

 

Total

 

1.0

 

1.0

 

 

 —

 

 —

 

1.0

 

1.0

 

24.0

 

22.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nonproductive wells drilled

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development

 

1.0

 

1.0

 

 

 —

 

 —

 

 —

 

 —

 

1.0

 

1.0

 

Exploratory

 

 —

 

 —

 

 

 —

 

 —

 

 —

 

 —

 

1.0

 

0.6

 

Total

 

1.0

 

1.0

 

 

 —

 

 —

 

 —

 

 —

 

2.0

 

1.6

 

 

Present Activities

As of December 31, 2017, we had no wells being drilled.

Delivery Commitments

We had no delivery commitments in the year ended December 31, 2017.

Productive Wells

Our working interests in productive wells were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

Predecessor

 

 

December 31, 

 

 

June 30,

 

 

2017

 

2016

 

 

2016

 

    

Gross

    

Net

    

Gross

    

Net

  

  

Gross

    

Net

Natural gas

 

76

 

50

 

100

 

73

 

 

103

 

76

Crude oil

 

501

 

409

 

516

 

425

 

 

532

 

436

Total

 

577

 

459

 

616

 

498

 

 

635

 

512

 

 

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Acreage

Working interests in developed and undeveloped acreage were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

December 31, 2017

 

 

Developed Acres

 

Undeveloped Acres

 

Total Acres

 

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

Onshore

 

11,529

 

2,904

 

46,570

 

22,170

 

58,099

 

25,074

Offshore

 

513,497

 

419,070

 

68,810

 

35,176

 

582,307

 

454,246

Total

 

525,026

 

421,974

 

115,380

 

57,346

 

640,406

 

479,320

 

The following table summarizes potential expiration of our onshore and offshore undeveloped acreage.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

Year Ended December 31, 

 

 

2018

 

2019

 

2020

 

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

Onshore

 

502

 

251

 

1,069

 

605

 

4,624

 

3,118

Offshore

 

 -

 

 -

 

6,456

 

5,364

 

 -

 

 -

Total

 

502

 

251

 

7,525

 

5,969

 

4,624

 

3,118

 

Capital Expenditures, Including Acquisitions and Costs Incurred

The supplementary data presented reflects information for all of our oil and natural gas producing activities. Costs incurred for oil and natural gas property acquisition, exploration and development activities were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

Predecessor

 

 

Year Ended

 

 

Six Months Ended

 

 

 

 

 

 

 

 

December 31, 

 

 

December 31, 

 

Year Ended June 30,

 

    

2017

  

  

2016

    

2016

    

2015

 

 

 

 

 

 

(in thousands)

Property acquisitions

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved

 

$

96

 

 

$

1,500

 

$

26,400

 

$

 —

Unevaluated

 

 

 —

 

 

 

 —

 

 

 —

 

 

2,304

Exploration costs

 

 

669

 

 

 

 —

 

 

1,400

 

 

38,183

Development cost

 

 

62,283

 

 

 

22,300

 

 

57,400

 

 

608,605

 

 

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Oil and Natural Gas Production and Prices

Our average daily production represents our net ownership and includes royalty interests and net profit interests owned by us. Our average daily production and average sales prices (excluding derivative gain or loss) follow. For other selected financial data including operating revenues, net income and total assets, see “Item 6. Selected Financial Data.”

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

Predecessor

 

 

 

Year Ended

 

 

Six Months Ended

 

 

 

 

 

 

 

 

 

December 31, 

 

 

December 31, 

 

Year Ended June 30,

 

 

    

2017

  

  

2016

    

2016

    

2015

 

Sales Volumes per Day

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

47.3

 

 

 

73.3

 

 

92.8

 

 

102.7

 

NGLs (MBbls)

 

 

0.8

 

 

 

0.9

 

 

2.5

 

 

2.7

 

Crude oil (MBbls)

 

 

25.5

 

 

 

29.8

 

 

34.5

 

 

39.1

 

Total (MBOE)

 

 

34.2

 

 

 

42.9

 

 

52.5

 

 

58.9

 

Percent of BOE from crude oil and NGLs

 

 

77

%

 

 

72

%  

 

71

%  

 

71

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Sales Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas per Mcf

 

$

3.11

 

 

$

2.75

 

$

2.04

 

$

3.13

 

NGLs per Bbl

 

$

29.62

 

 

$

21.12

 

$

16.09

 

$

28.09

 

Crude oil per Bbl

 

$

51.69

 

 

$

46.71

 

$

42.18

 

$

71.82

 

Sales price per BOE

 

$

43.57

 

 

$

37.57

 

$

32.10

 

$

54.41

 

 

Oil and Natural Gas Production, Prices and Production Costs – Significant Fields

The following field contains 15% or more of our total proved reserves as of December 31, 2017. Our average daily production, average sales prices and production costs for that field are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

Predecessor

 

 

 

Year Ended

 

 

Six Months Ended

 

 

 

 

 

 

 

 

 

December 31, 

 

 

December 31, 

 

Year Ended June 30,

 

 

    

2017

  

  

2016

    

2016

    

2015

 

West Delta 73

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales Volumes per Day

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

1.8

 

 

 

1.8

 

 

3.0

 

 

4.3

 

NGLs (MBbls)

 

 

 —

 

 

 

 —

 

 

0.1

 

 

0.1

 

Crude oil (MBbls)

 

 

3.0

 

 

 

3.8

 

 

4.8

 

 

4.9

 

Total (MBOE)

 

 

3.3

 

 

 

4.1

 

 

5.4

 

 

5.8

 

Percent of BOE from crude oil and NGLs

 

 

91.0

%  

 

 

93.0

%  

 

91.0

%  

 

86.0

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Sales Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas per Mcf

 

$

3.35

 

 

$

4.31

 

$

2.34

 

$

3.46

 

NGLs per Bbl

 

$

 —

 

 

$

 —

 

$

14.72

 

$

25.18

 

Crude oil per Bbl

 

$

52.03

 

 

$

46.01

 

$

42.91

 

$

68.63

 

Production cost per BOE

 

$

26.14

 

 

$

15.90

 

$

16.99

 

$

19.91

 

 

 

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Production Unit Costs per BOE

Our production unit costs per BOE follow. Production costs include lease operating expense and production taxes.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

Predecessor

 

 

Year Ended

 

 

Six Months Ended

 

 

 

 

 

 

 

 

December 31, 

 

 

December 31, 

 

Year Ended June 30,

 

    

2017

  

  

2016

    

2016

    

2015

Average Cost per BOE

 

 

 

 

 

 

 

 

 

 

 

 

 

Production costs

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

 

 

 

 

 

 

 

 

 

 

 

 

Insurance expense

 

$

1.88

 

 

$

1.60

 

$

1.97

 

$

1.86

Workover and maintenance

 

 

3.54

 

 

 

2.81

 

 

3.00

 

 

3.02

Direct lease operating expense

 

 

20.17

 

 

 

12.89

 

 

12.11

 

 

16.04

Total lease operating expense

 

 

25.59

 

 

 

17.30

 

 

17.08

 

 

20.92

Production taxes

 

 

0.11

 

 

 

0.06

 

 

0.08

 

 

0.39

Total production costs

 

$

25.70

 

 

$

17.36

 

$

17.16

 

$

21.31

 

Derivative Activities

We are actively engaged in a hedging program designed to manage our commodity price risk and to enhance the certainty and predictability of cash flow. For further information regarding our risk management activities, please read Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in this Form 10‑K.

Marketing and Customers

We market a majority of our oil and natural gas production. Our oil and natural gas production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

Chevron USA (“Chevron”), Shell Trading Company (“Shell”), Plains Marketing, LP (“Plains”) and Trafigura Trading, LLC (“Trafigura”) accounted for approximately 26%, 25%, 18% and 12%, respectively, of our total oil and natural gas revenues during year ended December 31, 2017. Trafigura, Chevron and Shell accounted for approximately 27%, 26%, and 26%, respectively, of our total oil and natural gas revenues during the six months ended December 31, 2016. Trafigura accounted for approximately 22% of our total oil and natural gas revenues during the year ended June 30, 2016. Chevron accounted for approximately 22% and 24% of our total oil and natural gas revenues during the years ended June 30, 2016 and 2015, respectively. Shell accounted for approximately 21% and 29% of our total oil and natural gas revenues during the years ended June 30, 2016 and 2015, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 26% of our total oil and natural gas revenues during the year ended June 30, 2015. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Trafigura, Chevron or Shell curtailed their purchases. Although we believe we will be able to sell our production, prices may vary depending on demand.

We transport a portion of our oil and natural gas through third-party gathering systems and pipelines. Transportation space on these gathering systems and pipelines is normally readily available. Our ability to market our oil and natural gas has at times been limited or delayed due to restricted or unavailable transportation space or weather damage.

Competition

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors include larger independent oil and gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than ours. These additional resources can be particularly important in reviewing prospects and purchasing

 

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properties. Our competitors may also have a greater ability to continue drilling activities during periods of low oil and natural gas prices and to absorb the burden of current and future governmental regulations and taxation. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe will impact attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted. Please read Item 1A. Risk Factors “—Competition for oil and natural gas properties and prospects is intense, and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.”

Government Regulation

Our oil and natural gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations may be subject to amendment by the respective regulating agency or re-interpretation by a court, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

Regulations affecting production. The jurisdictions in which we operate, particularly the outer continental shelf (“OCS”), generally require permits for drilling operations, drilling bonds and operating reports and impose other requirements relating to the exploration and production of oil and natural gas. Those jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many jurisdictions impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. There is generally no regulation of wellhead prices or other, similar direct economic regulation of production, but there can be no assurance that this will remain true in the future.

In the event we conduct operations on federal, state or Indian oil and natural gas leases onshore in the future, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and on-site security regulations and other appropriate permits issued by the Bureau of Land Management or other relevant federal or state agencies.

Regulations affecting sales. The sales prices of oil, NGLs and natural gas are not presently regulated but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of natural gas we produce, as well as the revenues we receive for sales of such production. FERC is under new leadership and may implement new rules and regulations affecting the price and terms of access to interstate pipeline transportation.  For example, FERC may implement new rules and regulations to address the tax law changes in the Tax Cuts and Jobs Act of 2017, which could have the effect of lowering the rates that interstate pipelines can charge.  In certain circumstances, FERC initiatives also may affect the intrastate transportation of natural gas. The stated purpose of many of FERC’s regulations is to promote competition among the various sectors of

 

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the natural gas industry. To the extent FERC changes its regulations, we do not believe that we will be affected in a manner materially different than other natural gas producers in our areas of operation.

The price we receive from the sale of oil, natural gas and NGLs is affected by the cost of transporting those products to market. Rates charged and terms of service for the interstate pipeline transportation of oil, NGLs and other refined petroleum products also are regulated by FERC. FERC has established an indexing methodology for changing the interstate transportation rates for oil pipelines, which allows such pipelines to take an annual inflation-based rate increase. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs, which may have the effect of reducing wellhead prices for oil, natural gas and NGLs.

Market manipulation and market transparency regulations. Under the Energy Policy Act of 2005 (“EPAct 2005”), FERC has regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity” in order to enforce the anti-market manipulation provisions in the EPAct 2005. The Commodity Futures Trading Commission (“CFTC”) also holds authority to regulate certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. Likewise, the Federal Trade Commission (“FTC”) holds authority to regulate wholesale petroleum markets pursuant to the Federal Trade Commission Act and the Energy Independence and Security Act of 2007. With regard to our physical purchases and sales of natural gas, NGLs and crude oil, our gathering or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC, FTC and/or the CFTC. These agencies hold substantial enforcement authority, including FERC’s ability to assess civil penalties of up to $1 million per day per violation, adjusted for inflation, or, for the CFTC, triple the monetary gain to the violator, order disgorgement of profits, and recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

FERC has issued certain market transparency rules pursuant to its EPAct 2005 authority, which may affect some or all of our operations. FERC issued a final rule in 2007, as amended by subsequent orders on rehearing (“Order 704”), which requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including natural gas producers, gatherers, processors, and marketers, to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to, the formation of price indices, as explained in the order. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. FERC’s civil penalty authority under EPAct 2005 applies to violations of Order 704.

Oil Pipeline Regulations. We own interests in oil pipelines regulated by FERC under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 (“EPAct of 1992”), and the rules and regulations promulgated under those laws and, thus, have interstate tariffs on file with FERC setting forth our interstate transportation rates and charges and the rules and regulations applicable to our jurisdictional transportation service. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil, NGLs and refined petroleum products pipelines, be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. Under the ICA, shippers may challenge new or existing rates or services. FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. A successful rate challenge could result in an oil pipeline paying refunds for the period that the rate was in effect and/or reparations for up to two years prior to the filing of a complaint. FERC generally has not investigated oil pipeline rates on its own initiative. Under the EPAct of 1992, oil pipeline rates in effect for the 365‑day period ending on the date of enactment of the EPAct of 1992 are deemed to be just and reasonable under the ICA if such rates were not subject to complaint, protest or investigation during that 365‑day period. These rates are commonly referred to as “grandfathered rates.” FERC may change grandfathered rates upon complaint only after it is shown that (i) a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate; (ii) the complainant was contractually barred from challenging the rate prior to enactment of the EPAct of 1992 and filed the complaint within 30 days of the expiration of the

 

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contractual bar; or (iii) a provision of the tariff is unduly discriminatory or preferential. The EPAct of 1992 places no similar limits on challenges to a provision of an oil pipeline tariff as unduly discriminatory or preferential.

The EPAct of 1992 further required FERC to establish a simplified and generally applicable ratemaking methodology for interstate oil pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows oil pipelines to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, plus 2.65 percent. Rate increases made under the index are subject to protest, but the scope of the protest proceeding is limited to an inquiry into whether the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. The indexing methodology is applicable to any existing rate, including a grandfathered rate. Indexing includes the requirement that, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. However, the pipeline is not required to reduce its rates below the level deemed just and reasonable under the EPAct of 1992.

While an oil pipeline, as a general rule, must use the indexing methodology to change its rates, FERC also retained cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach. A pipeline can follow a cost-of-service approach when seeking to increase its rates above the rate ceiling (or when seeking to avoid lowering rates to the reduced rate ceiling), provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can charge market-based rates if it establishes that it lacks significant market power in the affected markets. In addition, a pipeline can establish rates under settlement.

Outer Continental Shelf Regulations. Our operations on federal oil and natural gas leases in the Gulf of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the BOEM. These leases require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act (“OCSLA”). These laws and regulations are subject to change and may result in more stringent conditions and restrictions on activities that affect the environment. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (the “EPA”), lessees must obtain a permit from the BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. In particular, to cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells, decommission or remove platforms and pipelines, and clear the seafloor of obstructions at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable financial assurances that such obligations will be met. In July 2016, the agency issued a new NTL that went into effect on September 12, 2016 (the “September 2016 NTL”) and augments requirements for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to satisfy decommissioning obligations on the OCS. On January 6, 2017, the BOEM announced that it was extending the implementation timeline for providing financial assurance under the September 2016 NTL by an additional six months (the “January 2017 Extension”). This January 2017 Extension of time applied to leases, rights-of-way and rights of use and easement for which there are co-lessees and/or predecessors in interest. On February 17, 2017, the BOEM announced that it was withdrawing orders issued in December 2016 to operators of so-called “sole liability properties” – leases, rights-of-way and rights of use and easement for which the holder is the only liable party – to allow additional time for review of its financial assurance program.  On June 22, 2017, the BOEM extended the timeline for implementation of the September 2016 NTL indefinitely.

Gathering Regulations. Section 1(b) of the federal Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. Although FERC has not made any formal determinations with respect to any of the natural gas gathering pipeline facilities that we own, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities, however, has been the subject of substantial litigation and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on

 

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the one hand, and gathering facilities, on the other, is a fact-based determination made by FERC on a case-by-case basis. The classification and regulation of our gathering lines may be subject to change based on future determinations by FERC, the courts or the U.S. Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. Our gathering operations may also be subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner differently than other companies in our areas of operation.

Environmental Regulations

Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the handling, discharge and disposition of waste materials, the reclamation and abandonment of wells, sites and facilities, the establishment of financial assurance requirements for oil spill response costs and the decommissioning of offshore facilities and the remediation of contamination resulting from our operations. These laws and regulations may impose liabilities for noncompliance and contamination arising from our operations and may result in the assessment of sanctions, including administrative, civil and criminal penalties, or require suspension or cessation of operations in affected areas.

The environmental laws and regulations, as amended from time to time, applicable to us and our operations include, among others, the following United States federal laws and regulations:

·

Clean Air Act, which governs the emission of air pollutants from many sources, imposes various pre-construction, monitoring and reporting requirements, and is relied upon by the EPA as authority for adopting climate change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;

·

Clean Water Act, which governs discharges of pollutants from facilities into waters of the United States;

·

Comprehensive Environmental Response, Compensation and Liability Act, which imposes strict liability where releases of hazardous substances have occurred or are threatened to occur;

·

Resource Conservation and Recovery Act (the “RCRA”), which governs the management of solid waste, including hazardous wastes;

·

Endangered Species Act,  Marine Mammal Protection Act, and Migratory Bird Treaty Act, which govern the protection of animals, flora and fauna;

·

Oil Pollution Act of 1990, which imposes liabilities resulting from discharges of oil into navigable waters of the United States;

·

Emergency Planning and Community Right-to-Know Act, which requires implementing a safety hazard communication program and reporting of toxic chemicals used or produced in our operations;

·

Safe Drinking Water Act, which ensures the quality of public drinking water and governs underground injection and disposal activities; and

 

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·

U.S. Department of Interior regulations, which relate to offshore oil and natural gas operations in U.S. waters and impose obligations for establishing financial assurances for decommissioning obligations, liabilities for pollution cleanup costs resulting from operations, and potential liabilities for pollution damages.

Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. Because environmental costs and liabilities occur frequently in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements may change and become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production. We maintain insurance coverage for sudden and accidental spills and pollution emanating from our operations subject to time discovery and reporting limitations for third party damages, although we are not fully insured against all such risks. Our insurance coverage provides for the reimbursement to us of costs incurred from a well out of control for the containment and clean-up of materials that may be suddenly and accidentally released in the course of a scheduled well out of control as defined by the policy terms, but such insurance does not fully insure pollution and similar environmental risk.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or the re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal or remediation requirements, could have a material adverse effect on the Company’s financial position and the drilling program’s results of operations. For example, during October 2015, the EPA issued a final rule lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion for the 8‑hour primary and secondary ozone standards. The EPA established initial attainment and non-attainment designations for specific geographic locations under the revised standards on November 16, 2017. In a second example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the costs to manage and dispose of wastes generated from exploration and production activities. On an international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in an agreement that requires member countries to review and “represent a progression”  in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020 (the “Paris Agreement”). Although the Paris Agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions.  The United States announced its intention to withdraw from the Paris Agreement on June 1, 2017. With regard to safety-related requirements, the BSEE issued a final rule in April 2016 mandating more stringent design requirements and operational procedures for critical well control equipment used in oil and natural gas operations on the OCS. Among other things, this final rule imposes rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deep water and high temperature, high pressure drilling activities, establishment of safe drilling margins with respect to downhole mud weights that may be used during drilling activities, and enhanced reporting requirements to regulators. These recent regulatory initiatives, or any other future laws, rules or initiatives, which impose more stringent environmental or safety-related requirements in connection with our onshore and offshore oil and natural gas exploration and production operations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows.

Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”) and regulations adopted pursuant to OPA impose a variety of requirements on “responsible parties” related to the prevention of and response to oil spills into waters of the United States, including the OCS. A “responsible party” includes the owner or operator of an onshore facility, pipeline

 

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or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns joint and several, strict liability, without regard to fault, to each responsible party, for all containment and cleanup costs and a variety of public and private damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In January 2018, the BOEM issued a final rule that raised OPA’s damages liability cap to $137.66 million. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required under OPA for companies operating on the OCS will be increased. In any event, if there were to occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

Climate Change. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under the federal Clean Air Act that, among other things, establish certain permits and construction reviews designed to allow operations while ensuring the Prevention of Significant Deterioration (as defined in the federal Clean Air Act) of air quality by GHG emissions from large stationary sources that are already potential sources of significant, or criteria, pollutant emissions. The EPA has also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States, including onshore and offshore oil and gas production facilities. Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations; in June 2016, the EPA published new source performance standards that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and volatile organic compound emissions. In June 2017, the EPA proposed a two-year stay of certain requirements of this rule pending reconsideration.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and a number of states or groupings of states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of GHGs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that 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, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Employees

We had 168 employees at December 31, 2017, none of which were represented by labor unions or covered by any collective bargaining agreement. We consider relations with our employees to be satisfactory, and we have never experienced a work stoppage or strike. We regularly use independent consultants and contractors to perform various professional services in various areas, including in our exploration and development operations, production operations and certain administrative functions.

Available Information

We file or furnish annual, quarterly and current reports and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F

 

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Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1‑800‑SEC‑0330. Also, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents we file with the SEC at www.sec.gov.

Our website address is www.energyxxi.com. We make available, free of charge on or through our website, our Annual Reports on Form 10‑K, proxy statements, Quarterly Reports on Form 10‑Q and Current Reports on Form 8‑K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or accessible through, our website is not incorporated by reference into this Form 10‑K.

 

 

 

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Item 1A.  Risk Factors

The Exit Facility and our liquidity upon emergence will limit our available funding for exploration and development.  We may have difficulty obtaining additional credit, which could adversely affect our operations and financial position.

Historically, our Predecessor depended on the Prepetition Revolving Credit Facility for a portion of its capital needs. On the Emergence Date, by operation of the Plan, all outstanding obligations under Prepetition Revolving Credit Facility, the related collateral agreement and the credit agreements governing such obligations were cancelled.

Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into the Exit Facility, which consists of two facilities: (i) an Exit Term Loan facility resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Debtors’ Prepetition Revolving Credit Facility of approximately $74 million and (ii) the Exit Revolving Facility resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides for the making of revolving loans and the issuance of letters of credit. On the Emergence Date, the aggregate commitments under the Exit Revolving Facility were approximately $227.8 million, all of which was utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of ExxonMobil to secure certain plugging and abandonment obligations.

We may not be able to access adequate funding in the future as there is limited remaining available borrowing capacity contemplated under the Exit Facility. There is no certainty that any new capacity will be created or that the Exit Facility may be refinanced on economically advantageous terms.

As a complement to the Company’s capital plan, including the 2018 Capital Budget, the Company has retained Intrepid Partners LLC to assist with the consideration of possible alternatives for raising additional capital.  No determination has yet been made as to the form or amount of any such additional capital, but it could be in the form of debt, convertible debt, additional common stock or a new series of non-convertible or convertible preferred stock, as well as other financing structures.  There can be no assurance that any such capital-raising transaction will be consummated or, if consummated, when that transaction will occur.  Furthermore, the Company intends that any such financing would be structured in such a way that it would not preclude a strategic transaction.

If funding is not available when needed, or is available only on unfavorable terms, it could adversely affect (i) our ability to maintain our infrastructure, particularly in light of its maturity, high fixed costs, and required level of maintenance and repairs compared to other GoM Shelf producers, (ii) our development plans as currently anticipated, which could have a material adverse effect on our production, revenues, results of operations and liquidity, including our ability to develop our proved undeveloped reserves within the five year period required by the SEC, and (iii) our ability to meet our other obligations, including plugging and abandonment and decommissioning obligations.

The securities that may be issued by the Company as part of its current capital raise activities could have a dilutive effect to stockholders of the Company.

With respect to the Company’s current capital raise activities, no determination has yet been made as to the form that any such additional capital would take, but it could be in the form of debt, convertible debt, additional common stock or a new series of non-convertible or convertible preferred stock, as well as other financing structures.  The securities, if any, that are issued in order to raise capital could have a dilutive effect to the holdings of our stockholders of the Company.

Trading in our shares may be limited in volume, our stock price may be volatile and holders of our common stock may be unable to sell shares at or above the price at which they purchased them.

Since our common stock began trading on the NASDAQ on February 28, 2017 through March 2, 2018, the closing stock price for our common stock has ranged from $4.74 per share to $35.96 per share. Because of the limited trading volume in our shares, the ability of investors to purchase or sell shares may be constrained.  Furthermore, the market

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price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. Volatility in the market price of our common stock may prevent you from being able to sell your shares at or above the price you paid for your shares of common stock. The market price for our common stock could fluctuate significantly for various reasons, including our new capital structure as a result of the transactions contemplated by the Plan, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, strategic actions by us or our competitors, changes in government regulations, arrival and departure of key personnel, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Form 10-K.

Future sales of our common stock in the public market or the issuance of securities senior to our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and our ability to raise funds in stock offerings.

A large percentage of our shares of common stock are held by a relatively small number of investors. Further, we entered into a registration rights agreement with certain of those investors pursuant to which we agreed to file a registration statement with the SEC to facilitate potential future sales of such shares by them.  That registration statement was declared effective by the SEC on March 23, 2017. Sales by our stockholders of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur, could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities. For more information, please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Plan of Reorganization—Equity Interests.”

We are currently authorized to issue 100 million shares of common stock and 10 million shares of preferred stock of the Company with such designations, rights, preferences, privileges and restrictions as determined by the Board. As of March 2, 2018, we had outstanding approximately 33.3 million shares of common stock and 2.1 million warrants to purchase an aggregate of 2.1 million shares of common stock at an initial exercise price of $43.66 per share of common stock. We have also reserved approximately 1.9 million shares of common stock for future issuance to our directors, officers and employees as restricted stock, stock option or any other stock based compensation awards pursuant to Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), and may seek to reserve additional shares in the future. The potential issuance of such additional shares of common stock may create downward pressure on the future trading price of our common stock.

We may issue common stock or other equity securities senior to our common stock in the future for a number of reasons, including to finance acquisitions, to adjust our leverage ratio and to satisfy our obligations upon the exercise of warrants, other equity securities or for other reasons. We cannot predict the effect, if any, that future sales or issuances of shares of our common stock or other equity securities, or the availability of shares of common stock or such other equity securities for future sale or issuance, will have on the trading price of our common stock.

A new board of directors was appointed upon our emergence from bankruptcy, a new Chief Operating Officer began on February 2, 2017, a new President and Chief Executive Officer began on April 17, 2017, a new Chief Financial Officer began on August 24, 2017 and several directors have resigned from, or stated their intention not to stand for re-election to, the board of directors in recent months. The transition in our new board of directors and senior management team will be critical to our success.

Pursuant to our emergence from the Chapter 11 Cases, a new board of directors was appointed on the effective date of the Plan. At emergence, the new board was made up of six directors, and none of the new directors had previously served on the Board of the Predecessor Company. On February 2, 2017, we hired Scott M. Heck and appointed him to serve as our Chief Operating Officer of the Company, on April 17, 2017, we hired Douglas E. Brooks and appointed him as our new Chief Executive Officer and President, and on August 24, 2017, we hired T.J. Thom Cepak and appointed her to serve as our Chief Financial Officer of the Company.  In the last four months, George Kollitides and James W. Swent

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III, two of our independent directors have resigned because of their other professional commitments.  Additionally, Michael S. Reddin, the Company’s Chairman of the Board, notified the Company on February 17, 2018 of his decision not to stand for re-election as a director of the Company.  The ability of our new directors, the new Chief Executive Officer, new Chief Operating Officer and the new Chief Financial Officer to quickly expand their knowledge of our business plans, operations and strategies and our technologies will be critical to their ability to make informed decisions about our strategy and operations.  If our Board, Chief Executive Officer, Chief Operating Officer or Chief Financial Officer are not sufficiently informed to make such decisions, or have different views on the direction of the Company and other issues that will determine the future of the Company, our ability to compete effectively and profitably could be adversely affected and the future strategy and plans of the Company may differ materially from those of the past.

Our success depends on dedicated and skillful management and staff, whose departure could disrupt our business operations.

Our success depends on our ability to retain and attract experienced engineers, geoscientists and other professional staff.  We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team.  Any departures of key management or staff could cause disruptions in our business.

We and our subsidiaries believe we have provided the BOEM with all bonds or other surety in order to maintain compliance with BOEM regulations, although additional bonds could be required which may be costly and could potentially have negative impact on operating cash flows.

To ensure that the various obligations of lessees on the OCS, such as the cost to plug and abandon wells, decommission and remove platforms and pipelines, and to clear the seafloor of obstructions at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable financial assurances that such obligations will be met. Historically, the BOEM and its predecessors could exempt the lessees from posting such bonds or other assurances for the performance of these decommissioning obligations.  However, following the bankruptcy of another Gulf of Mexico operator in 2012, the BOEM commenced a reassessment of its offshore financial assurance program. In July 2016, the agency issued its September 2016 NTL that revised requirements for the posting of additional security to satisfy decommissioning obligations. Additionally, the September 2016 NTL eliminated the exemption from the posting of financial assurances.  On January 6, 2017, the BOEM announced its January 2017 Extension.  This January 2017 Extension of time applied to leases, rights-of-way and rights of use and easement for which there are co-lessees and/or predecessors in interest.  On February 17, 2017, the BOEM announced that it was withdrawing orders issued in December 2016 to operators of “sole liability properties” – leases, rights-of-way and rights of use and easement for which the holder is the only liable party – to allow additional time for review of its financial assurance program.  On June 22, 2017, the BOEM extended the timeline for implementation of the September 2016 NTL indefinitely.

We are a lessee and operator of oil and natural gas leases on the OCS and consequently, as of December 31, 2017, we have submitted approximately $182.4 million in performance bonds in the form of general or supplemental bonds to the BOEM that may be accessed and used by the BOEM to assure our commitment to comply with our lease obligations, including decommissioning obligations. We also maintained approximately $151.7 million in performance bonds issued not to the BOEM but rather to predecessor third party assignors, including certain state regulatory bodies for certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. In addition, we may be required to provide cash collateral to third party assignors and third party sureties in connection with these performance bonds.

The future cost of compliance with our existing supplemental bonding requirements, including such bonding obligations as reflected in the long-term financial assurance plan (“Long-Term Plan”) approved and executed by the BOEM on February 25, 2016, as such plan may be revised by the amended and supplemental plan submitted to the BOEM on June 28, 2016 (the “Proposed Plan Amendment”), or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding rules applicable to us or our subsidiaries’ properties could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide cash collateral to support the issuance of such bonds or other surety. While we and the BOEM have executed the Long-Term Plan, we have since submitted the Proposed Plan Amendment for the agency’s consideration

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and approval that would revise the Long-Term Plan. We can provide no assurance that we can continue in the future to obtain bonds or other surety or that we will have sufficient operating cash flows to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds as requested, the BSEE or the BOEM may have any of our operations on federal leases suspended or cancelled or otherwise impose monetary penalties, and any one or more of such actions could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity. For more information about the BOEM’s supplement bonding requirements, see “–Known Trends and Uncertainties–BOEM Supplemental Financial Assurance and/or Bonding Requirements.”

Unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

We may become responsible for unanticipated increases to or acceleration of costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith is often referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated or the decommissioning be accelerated, such as can happen after a hurricane, such costs may exceed the value of reserves remaining at any particular time. We may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations. Please also read “—We and our subsidiaries believe we have provided the BOEM with all bonds or other surety in order to maintain compliance with BOEM regulations, although additional bonds could be required which may be costly and could potentially have negative impact on operating cash flows.”

We are limited in our ability to book proved undeveloped reserves under the SEC’s rules.

We have included in this Form 10-K certain estimates of our proved reserves as of December 31, 2017 prepared in a manner consistent with our interpretation of the SEC rules relating to reserve estimation and disclosure requirements for oil and natural gas companies.  Current SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking.  For example, in connection with our most recent reserve report, we removed approximately 6 BOE of proved undeveloped reserves because of this five-year rule.

Delays in the development of our reserves or increases in costs to drill and develop such reserves reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. Please read “Business—Development of Proved Undeveloped Reserves.”

Production periods or reserve lives for Gulf of Mexico properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during their initial years of operation when compared to other regions in the U.S. Typically, 50% of the reserves of properties in the Gulf of Mexico are depleted within three to four years, with natural gas wells generally having a higher rate of depletion than oil wells. Due to high initial production rates, production of reserves from reservoirs in the Gulf of Mexico generally decline more rapidly than from other producing reservoirs. The vast majority of our existing operations are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas.

Unless we replace crude oil and natural gas reserves, our future reserves and production will decline.

A large portion of our drilling activity is located in mature oil-producing areas of the GoM Shelf. Accordingly, increases in our future crude oil and natural gas production depend on our success in developing, finding or acquiring additional reserves that are economically recoverable. If we are unable to replace reserves through drilling or acquisitions on economic terms, our level of production and cash flows will be adversely affected. In general, production

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from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves may be impaired if cash flow from operations remains limited and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to explore for, develop or acquire additional reserves.

Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices would adversely affect our financial results and impede our growth.

Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. For example, oil prices declined severely during 2015 with continued lower prices into 2016 and 2017.  The WTI crude oil price per barrel for the period from October 1, 2014 to December 31, 2017 ranged from a high of $91.01 to a low of $26.21, and the New York Mercantile Exchange (“NYMEX”) natural gas price per MMBtu for the period October 1, 2014 to December 31, 2017 ranged from a high of $4.49 to a low of $1.64. As of December 31, 2017, the spot market price for WTI was $60.42.  Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

·

domestic and foreign supplies of oil and natural gas;

·

price and quantity of foreign imports of oil and natural gas;

·

actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;

·

level of consumer product demand, including as a result of competition from alternative energy sources;

·

level of global oil and natural gas exploration and production activity;

·

domestic and foreign governmental regulations;

·

level of global oil and natural gas inventories;

·

political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America, Africa and Russia;

·

weather conditions;

·

technological advances affecting oil and natural gas production and consumption;

·

overall U.S. and global economic conditions; and

·

price and availability of alternative fuels.

Our financial condition, revenues, profitability and the carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. Any sustained periods of low prices for oil and natural gas are likely to materially and adversely affect our financial position, the quantities of oil and natural gas reserves that we can economically produce, our cash flow available for capital expenditures and our ability to access funds through the capital markets.

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Lower oil and gas prices and other factors may result in future ceiling test write-downs of our asset carrying values.

Under the full cost method of accounting at the end of each financial reporting period we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12‑month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net capitalized costs of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the amount of the discounted cash flows. Declines in oil prices may adversely affect our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce.

Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations include the Gulf of Mexico.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations are many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than being structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

Moreover, current operators in the Gulf of Mexico are required to commence decommissioning activities more quickly than was the case prior to the issuance of an NTL in 2010 by the Bureau of Ocean Energy, Management and Regulation (now BSEE) addressing the timely decommissioning of what is known as “idle iron”:  wells, platforms and pipelines that are no longer producing or serving exploration or support functions with respect to an operator’s lease. The idle iron NTL requires that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years’ time, with a two-year delay of such activities available under certain circumstances.  Platforms or other facilities no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs.

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 reserves.

This Form 10‑K contains estimates of our future net cash flows from our proved reserves. We base the estimated discounted future net cash flows from our proved reserves on average prices for the preceding 12 month period and costs in effect at the time of the estimate. Unless average commodity prices or reserves increase, the estimated discounted

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future net cash flows from our proved reserves would generally be expected to decrease. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

·

supply of and demand for oil and natural gas;

·

actual prices we receive for oil and natural gas;

·

the volume, pricing and duration of any future oil and natural gas hedging contracts;

·

our actual operating costs in producing oil and natural gas;

·

the amount and timing of our capital expenditures and decommissioning costs;

·

the amount and timing of actual production; and

·

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Estimates of reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

This Form 10-K contains estimates of our proved oil and natural gas reserves. Estimating crude oil and natural gas reserves is complex and inherently imprecise, and material inaccuracies in our reserve estimates will materially affect the quantities and values of our reserves. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our or our independent reserve engineering firm’s interpretations or assumptions used in arriving at estimates of our reserves prove to be inaccurate, the amount of oil and natural gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized in this Form 10-K. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, decommissioning liabilities and quantities of recoverable oil and natural gas reserves most likely will vary from estimates. In addition, the estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

As of December 31, 2017, approximately 11% of our total proved reserves were developed non-producing. There can be no assurance that all of those reserves will ultimately be produced.

While we have plans or are in the process of developing plans for exploiting and producing a majority of our proved reserves, there can be no assurance that all of those reserves will ultimately be produced. Furthermore, there can be no assurance that all of our developed non-producing reserves will ultimately be produced during the time periods we have planned, at the costs we have estimated, or at all, which could result in the write-off of previously recognized reserves.

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Most of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. We have leases on 502 gross acres (251 net) that could potentially expire during fiscal year 2018. We have limited capital to develop leases not currently held by production, or to re-lease or replace expiring leases.

Our drilling plans for areas not currently held by production are subject to change based upon various factors. Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. On our acreage that we do not operate, we have less control over the timing of drilling, therefore there is additional risk of expirations occurring in those sections.

We are not the operator on all of our properties and therefore are not in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on such properties.

We operated approximately 89% of our proved reserves at December 31, 2017.  However, with respect to the remaining 11% of our proved reserves, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

·

the timing and amount of capital expenditures;

·

the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

·

the operator’s expertise and financial resources;

·

approval of other participants in drilling wells;

·

selection of technology; and

·

the rate of production of the reserves.

Each of these factors and others could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Any future unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute exploration and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services may increase or decrease depending on the demand for services by other oil and gas companies. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Any future shortages or high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

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Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

Unlike other entities that are geographically diversified, we do not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. By operating only in the Gulf of Mexico and the U.S. Gulf Coast, our lack of diversification may:

·

subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate; and

·

result in our dependency upon a single or limited number of hydrocarbon basins.

In addition, the geographic concentration of our properties in the Gulf of Mexico and the U.S. Gulf Coast means that some or all of the properties could be affected should the region experience:

·

severe weather, such as hurricanes and other adverse weather conditions;

·

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

·

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

·

changes in the regulatory environment.

Because all or a number of the properties could experience many of the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.

Our business strategy includes the potential acquisition of exploration and production companies, producing properties and undeveloped leasehold interests. The successful acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:

·

acceptable prices for available properties;

·

amounts of recoverable reserves;

·

estimates of future oil and natural gas prices;

·

estimates of future exploratory, development and operating costs;

·

estimates of the costs and timing of decommissioning obligations; and

·

estimates of potential environmental and other liabilities.

Our assessment of the acquired properties will not reveal all existing or potential problems nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies. In the course of our due diligence, we historically have not physically inspected every well, platform or pipeline. Even if we had physically inspected each of these, our inspections may not have revealed structural and environmental problems, such as pipeline corrosion offshore. We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks. 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. If an acquired property does not perform as

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originally estimated, we may have an impairment, which could have a material adverse effect on our financial position and results of operations.

We may be unable to benefit from or successfully integrate the operations of the properties or businesses we acquire.

Integration of the operations of the properties we acquire with our existing business is a complex, time-consuming and costly process. Failure to successfully integrate the acquired businesses and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the acquired operations include, among other things:

·

operating a larger organization;

·

coordinating geographically disparate organizations, systems and facilities;

·

integrating corporate, technological and administrative functions;

·

diverting management’s attention from other business concerns;

·

diverting financial resources away from existing operations;

·

increasing our indebtedness; and

·